10-Q

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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, 2008

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

MARYLAND
(State of Incorporation of both registrants)

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

410-470-2800

(Registrants' telephone number, including area code)

NOT APPLICABLE

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

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

         Indicate by check mark whether Constellation Energy Group, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
(Check one):

Large accelerated filer ý Accelerated filer o Non-accelerated filer o
(Do not check if a smaller
reporting company) Smaller reporting company o

         Indicate by check mark whether Baltimore Gas and Electric Company is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
(Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer ý
(Do not check if a smaller
reporting company) Smaller reporting company o

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

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

Common Stock, without par value 178,415,808 shares outstanding
of Constellation Energy Group, Inc. on October 31, 2008.

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

TABLE OF CONTENTS

			Page
Part I—Financial Information
	Item 1—Financial Statements
		Constellation Energy Group, Inc. and Subsidiaries
		Consolidated Statements of Income (Loss)	3
		Consolidated Statements of Comprehensive Income (Loss)	3
		Consolidated Balance Sheets	4
		Consolidated Statements of Cash Flows	6
		Baltimore Gas and Electric Company and Subsidiaries
		Consolidated Statements of Income (Loss)	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	36
		Strategy	36
		Business Environment	37
		Events of 2008	37
		Results of Operations	40
		Financial Condition	58
		Capital Resources	63
	Item 3—Quantitative and Qualitative Disclosures About Market Risk		67
	Items 4 and 4(T)—Controls and Procedures		67
Part II—Other Information			68
	Item 1—Legal Proceedings		68
	Item 1A—Risk Factors		68
	Item 2—Unregistered Sales of Equity Securities and Use of Proceeds; Issuer Purchases of Equity Securities		73
	Item 4—Submission of Matters to Vote of Security Holders		73
	Item 5—Other Information		74
	Item 6—Exhibits		76
	Signature		78

2

PART 1—FINANCIAL INFORMATION

Item 1—Financial Statements

CONSOLIDATED STATEMENTS OF INCOME (LOSS) (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

		Three Months Ended September 30,						Nine Months Ended September 30,
		2008			2007			2008			2007
		(In millions, except per share amounts)
Revenues
	Nonregulated revenues	$	4,351.0		$	4,965.4		$	12,187.2		$	13,332.1
	Regulated electric revenues		822.3			778.2			1,980.3			1,837.3
	Regulated gas revenues		150.3			112.8			724.4			674.4
	Total revenues		5,323.6			5,856.4			14,891.9			15,843.8
Expenses
	Fuel and purchased energy expenses		4,318.0			4,549.7			11,620.5			12,451.6
	Operating expenses		482.9			653.6			1,784.5			1,802.7
	Impairments and other costs		477.1			—			477.1			20.2
	Merger and strategic alternatives costs		39.2			—			39.2			—
	Workforce reduction costs		2.2			—			2.2			2.3
	Depreciation, depletion, and amortization		134.3			138.3			424.5			413.5
	Accretion of asset retirement obligations		17.2			16.0			50.8			51.9
	Taxes other than income taxes		81.1			73.7			227.0			219.7
	Total expenses		5,552.0			5,431.3			14,625.8			14,961.9
Gains on Sales of Assets			—			—			91.5			—
(Loss) Income from Operations			(228.4	)		425.1			357.6			881.9
Gains on Sale of CEP LLC Equity			—			39.2			—			52.1
Other (Expense) Income			(16.1	)		29.1			41.3			116.7
Fixed Charges
	Interest expense		100.0			80.3			252.3			231.7
	Interest capitalized and allowance for borrowed funds used during construction		(10.5	)		(5.2	)		(26.2	)		(13.6	)
	BGE preference stock dividends		3.3			3.3			9.9			9.9
	Total fixed charges		92.8			78.4			236.0			228.0
(Loss) Income from Continuing Operations Before Income Taxes			(337.3	)		415.0			162.9			822.7
Income Tax (Benefit) Expense			(111.6	)		164.3			71.4			258.4
(Loss) Income from Continuing Operations			(225.7	)		250.7			91.5			564.3
	Income (Loss) from discontinued operations, net of income taxes of $0.7 and $1.5, respectively		—			0.7			—			(0.9	)
Net (Loss) Income		$	(225.7	)	$	251.4		$	91.5		$	563.4
(Loss) Earnings Applicable to Common Stock		$	(225.7	)	$	251.4		$	91.5		$	563.4
Average Shares of Common Stock Outstanding—Basic			178.4			180.5			178.3			180.5
Average Shares of Common Stock Outstanding—Diluted			179.5			182.8			180.0			182.8
(Loss) Earnings Per Common Share from Continuing Operations—Basic		$	(1.27	)	$	1.39		$	0.51		$	3.13
	Loss from discontinued operations		—			—			—			(0.01	)
(Loss) Earnings Per Common Share—Basic		$	(1.27	)	$	1.39		$	0.51		$	3.12
(Loss) Earnings Per Common Share from Continuing Operations—Diluted		$	(1.27	)	$	1.37		$	0.51		$	3.09
	Income (Loss) from discontinued operations		—			0.01			—			(0.01	)
(Loss) Earnings Per Common Share—Diluted		$	(1.27	)	$	1.38		$	0.51		$	3.08
Dividends Declared Per Common Share		$	0.4775		$	0.435		$	1.4325		$	1.305

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

				Three Months Ended September 30,						Nine Months Ended September 30,
				2008			2007			2008			2007
				(In millions)
Net (Loss) Income				$	(225.7	)	$	251.4		$	91.5		$	563.4
	Other comprehensive income (loss) (OCI)
		Hedging instruments:
			Reclassification of net (gain) loss on hedging instruments from OCI to net income, net of taxes		(166.4	)		275.1			(88.4	)		833.4
			Net unrealized loss on hedging instruments, net of taxes		(1,059.4	)		(360.0	)		(186.0	)		(498.4	)
		Available-for-sale securities:
			Reclassification of net loss (gain) on sales of securities from OCI to net income, net of taxes		8.9			(0.5	)		10.5			(3.3	)
			Net unrealized (loss) gain on securities, net of taxes		(79.1	)		(13.0	)		(107.8	)		0.7
		Defined benefit obligations:
			Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes		5.4			5.8			15.9			18.3
		Net unrealized gain on foreign currency, net of taxes			0.5			3.3			0.1			6.4
Comprehensive (Loss) Income				$	(1,515.8	)	$	162.1		$	(264.2	)	$	920.5

See Notes to Consolidated Financial Statements.

3

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

			September 30, 2008*			December 31, 2007
			(In millions)
Assets
	Current Assets
		Cash and cash equivalents	$	1,434.0		$	1,095.9
		Accounts receivable (net of allowance for uncollectibles of $162.0 and $44.9, respectively)		4,041.7			4,289.5
		Fuel stocks		912.9			591.3
		Materials and supplies		227.9			207.5
		Derivative assets		1,604.7			760.6
		Unamortized energy contract assets		67.0			32.0
		Deferred income taxes		—			300.7
		Other		727.7			408.1
		Total current assets		9,015.9			7,685.6
Investments and Other Noncurrent Assets
		Nuclear decommissioning trust funds		1,168.6			1,330.8
		Other investments		475.4			542.2
		Regulatory assets (net)		511.9			576.2
		Goodwill		7.5			261.3
		Derivative assets		1,006.0			1,030.2
		Unamortized energy contract assets		160.8			178.3
		Other		397.8			370.6
		Total investments and other noncurrent assets		3,728.0			4,289.6
Property, Plant and Equipment
		Property, plant and equipment		15,200.9			14,138.2
		Nuclear fuel (net of amortization)		395.5			374.3
		Accumulated depreciation		(4,986.6	)		(4,745.4	)
		Net property, plant and equipment		10,609.8			9,767.1
	Total Assets		$	23,353.7		$	21,742.3

* Unaudited

See Notes to Consolidated Financial Statements.

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

4

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

			September 30, 2008*			December 31, 2007
			(In millions)
Liabilities and Equity
	Current Liabilities
		Short-term borrowings	$	1,249.5		$	14.0
		Current portion of long-term debt		644.2			380.6
		Accounts payable and accrued liabilities		2,650.5			2,630.1
		Customer deposits and collateral		127.8			146.6
		Derivative liabilities		1,115.8			1,134.3
		Unamortized energy contract liabilities		390.6			392.2
		Deferred income taxes		42.3			—
		Accrued expenses and other		697.0			956.0
		Total current liabilities		6,917.7			5,653.8
	Deferred Credits and Other Noncurrent Liabilities
		Deferred income taxes		1,061.4			1,588.5
		Asset retirement obligations		970.6			917.6
		Derivative liabilities		1,171.1			1,118.9
		Unamortized energy contract liabilities		984.7			1,218.6
		Defined benefit obligations		781.2			828.6
		Deferred investment tax credits		45.7			50.5
		Other		150.5			155.9
		Total deferred credits and other noncurrent liabilities		5,165.2			5,878.6
	Long-term Debt, net of current portion			6,201.8			4,660.5
	Minority Interests			20.4			19.2
	BGE Preference Stock Not Subject to Mandatory Redemption			190.0			190.0
	Common Shareholders' Equity
		Common stock		2,586.7			2,513.3
		Retained earnings		3,720.2			3,919.5
		Accumulated other comprehensive loss		(1,448.3	)		(1,092.6	)
		Total common shareholders' equity		4,858.6			5,340.2
	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity		$	23,353.7		$	21,742.3

* Unaudited

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

5

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

Nine Months Ended September 30,				2008			2007
				(In millions)
Cash Flows From Operating Activities
	Net income			$	91.5		$	563.4
	Adjustments to reconcile to net cash (used in) provided by operating activities
		Depreciation, depletion, and amortization			424.5			413.5
		Amortization of nuclear fuel			91.2			84.5
		Amortization of energy contracts			(193.8	)		(196.7	)
		All other amortization			18.2			8.4
		Accretion of asset retirement obligations			50.8			51.9
		Deferred income taxes			45.0			118.7
		Investment tax credit adjustments			(4.8	)		(5.0	)
		Deferred fuel costs			40.8			(248.7	)
		Defined benefit obligation expense			77.2			105.7
		Defined benefit obligation payments			(111.4	)		(153.7	)
		Workforce reduction costs			2.2			2.3
		Impairments and other costs			477.1			20.2
		Gains on sale of CEP LLC equity			—			(52.1	)
		Gains on sales of assets and investments			(103.8	)		—
		Gains on termination of contracts			(81.6	)		—
		Equity in earnings of affiliates less than dividends received			1.1			36.6
		Derivative power sales contracts classified as financing activities under SFAS No. 149			(37.1	)		15.1
		Changes in working capital
			Accounts receivable, excluding margin		221.2			(118.1	)
			Derivative assets and liabilities, excluding collateral		(935.0	)		(78.9	)
			Net collateral and margin		(568.6	)		109.8
			Materials, supplies, and fuel stocks		(231.8	)		10.9
			Other current assets		(134.7	)		(58.8	)
			Accounts payable and accrued liabilities		57.2			100.4
			Other current liabilities		(270.5	)		(107.3	)
		Other			51.1			(5.4	)
	Net cash (used in) provided by operating activities				(1,024.0	)		616.7
Cash Flows From Investing Activities
	Investments in property, plant and equipment				(1,360.5	)		(920.3	)
	Acquisitions, net of cash acquired				(316.5	)		(344.1	)
	Investments in nuclear decommissioning trust fund securities				(365.4	)		(514.6	)
	Proceeds from nuclear decommissioning trust fund securities				346.7			505.8
	Proceeds from sales of property, plant and equipment				226.8			—
	Proceeds from sales of investments and other assets				14.4			5.6
	Contract and portfolio acquisitions				—			(474.2	)
	Issuances of loans receivable				—			(19.0	)
	Repayments of loans receivable				26.0			31.9
	Decrease (increase) in restricted funds				8.3			(26.5	)
	Other				(4.1	)		(70.8	)
	Net cash used in investing activities				(1,424.3	)		(1,826.2	)
Cash Flows From Financing Activities
	Net issuance of short-term borrowings				1,207.5			—
	Proceeds from issuance of common stock				17.6			47.7
	Proceeds from issuance of long-term debt (includes $1 billion proceeds from MidAmerican Energy Holdings Company)				2,100.0			647.2
	Repayment of long-term debt				(265.7	)		(740.2	)
	Debt issuance costs				(50.6	)		—
	Common stock dividends paid				(250.7	)		(226.8	)
	Reacquisition of common stock				(16.2	)		(114.4	)
	Proceeds from contract and portfolio acquisitions				—			847.8
	Derivative power sales contracts classified as financing activities under SFAS No. 149				37.1			(15.1	)
	Other				7.4			25.9
	Net cash provided by financing activities				2,786.4			472.1
Net Increase (Decrease) in Cash and Cash Equivalents					338.1			(737.4	)
Cash and Cash Equivalents at Beginning of Period					1,095.9			2,289.1
Cash and Cash Equivalents at End of Period				$	1,434.0		$	1,551.7

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 (LOSS) (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

			Three Months Ended September 30,						Nine Months Ended September 30,
			2008			2007			2008			2007
			(In millions)
Revenues
	Electric revenues		$	822.4		$	778.2		$	1,980.5		$	1,837.3
	Gas revenues			155.5			118.7			740.0			688.8
	Total revenues			977.9			896.9			2,720.5			2,526.1
Expenses
	Operating expenses
		Electricity purchased for resale		556.6			522.6			1,416.2			1,117.7
		Gas purchased for resale		107.5			70.6			505.2			457.6
		Operations and maintenance		139.5			134.8			409.9			389.2
		Merger and strategic alternatives costs		11.1			—			11.1			—
	Depreciation and amortization			49.5			58.4			171.2			175.8
	Taxes other than income taxes			44.1			44.0			130.7			132.8
	Total expenses			908.3			830.4			2,644.3			2,273.1
Income from Operations				69.6			66.5			76.2			253.0
Other Income				9.0			9.2			23.4			19.2
Fixed Charges
	Interest expense			38.6			35.3			105.6			92.4
	Allowance for borrowed funds used during construction			(1.2	)		(0.7	)		(3.3	)		(1.8	)
	Total fixed charges			37.4			34.6			102.3			90.6
Income (Loss) Before Income Taxes				41.2			41.1			(2.7	)		181.6
Income Taxes				18.0			13.4			1.9			67.7
Net Income (Loss)				23.2			27.7			(4.6	)		113.9
Preference Stock Dividends				3.3			3.3			9.9			9.9
Earnings (Loss) Applicable to Common Stock			$	19.9		$	24.4		$	(14.5	)	$	104.0

See Notes to Consolidated Financial Statements.

7

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

				September 30, 2008*			December 31, 2007
				(In millions)
Assets
	Current Assets
		Cash and cash equivalents		$	10.6		$	17.6
		Accounts receivable (net of allowance for uncollectibles of $29.6 and $20.3, respectively)			193.6			316.7
		Accounts receivable, unbilled (net of allowance for uncollectibles of $0.8 and $0.8, respectively)			155.5			209.5
		Investment in cash pool, affiliated company			63.1			78.4
		Accounts receivable, affiliated companies			2.3			4.2
		Fuel stocks			172.9			98.8
		Materials and supplies			42.3			42.7
		Prepaid taxes other than income taxes			67.1			49.9
		Regulatory assets (net)			86.9			74.9
		Restricted cash			44.5			39.2
		Income taxes refundable			94.4			—
		Other			2.0			7.4
		Total current assets			935.2			939.3
	Investments and Other Assets
		Regulatory assets (net)			511.9			576.2
		Receivable, affiliated company			167.8			149.2
		Other			129.2			148.1
		Total investments and other assets			808.9			873.5
	Utility Plant
		Plant in service
			Electric		4,425.8			4,244.4
			Gas		1,209.5			1,181.7
			Common		452.3			456.1
			Total plant in service		6,087.6			5,882.2
		Accumulated depreciation			(2,163.8	)		(2,080.8	)
		Net plant in service			3,923.8			3,801.4
		Construction work in progress			235.4			166.4
		Plant held for future use			2.6			2.4
		Net utility plant			4,161.8			3,970.2
	Total Assets			$	5,905.9		$	5,783.0

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

8

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

			September 30, 2008*			December 31, 2007
			(In millions)
Liabilities and Equity
	Current Liabilities
		Short-term borrowings	$	189.0		$	—
		Current portion of long-term debt		142.2			375.0
		Accounts payable and accrued liabilities		188.5			182.4
		Accounts payable and accrued liabilities, affiliated companies		113.2			164.5
		Customer deposits and collateral		73.2			70.5
		Current portion of deferred income taxes		46.1			44.1
		Accrued taxes		19.5			34.4
		Accrued expenses and other		107.9			96.3
		Total current liabilities		879.6			967.2
	Deferred Credits and Other Liabilities
		Deferred income taxes		816.7			785.6
		Payable, affiliated company		245.5			243.7
		Deferred investment tax credits		10.9			11.9
		Other		24.8			33.6
		Total deferred credits and other liabilities		1,097.9			1,074.8
	Long-term Debt
		Rate stabilization bonds		589.9			623.2
		First refunding mortgage bonds		—			119.7
		Other long-term debt		1,508.0			1,214.5
		6.20% deferrable interest subordinated debentures due October 15, 2043 to wholly owned BGE Capital Trust II relating to trust preferred securities		257.7			257.7
		Long-term debt of nonregulated businesses		25.0			25.0
		Unamortized discount and premium		(2.4	)		(2.6	)
		Current portion of long-term debt		(142.2	)		(375.0	)
		Total long-term debt		2,236.0			1,862.5
	Minority Interest			17.0			16.8
	Preference Stock Not Subject to Mandatory Redemption			190.0			190.0
	Common Shareholder's Equity
		Common stock		912.2			912.2
		Retained earnings		572.6			758.8
		Accumulated other comprehensive income		0.6			0.7
		Total common shareholder's equity		1,485.4			1,671.7
	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity		$	5,905.9		$	5,783.0

* 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,				2008			2007
				(In millions)
Cash Flows From Operating Activities
	Net (loss) income			$	(4.6	)	$	113.9
	Adjustments to reconcile to net cash provided by operating activities
		Depreciation and amortization			171.2			175.8
		Other amortization			10.2			9.5
		Deferred income taxes			20.5			85.5
		Investment tax credit adjustments			(1.0	)		(1.2	)
		Deferred fuel costs			40.8			(248.7	)
		Defined benefit plan expenses			27.3			31.7
		Allowance for equity funds used during construction			(6.1	)		(3.4	)
		Changes in
			Accounts receivable		177.1			(125.7	)
			Accounts receivable, affiliated companies		1.9			(0.7	)
			Materials, supplies, and fuel stocks		(73.7	)		(6.5	)
			Other current assets		(106.0	)		47.0
			Accounts payable and accrued liabilities		6.1			(49.2	)
			Accounts payable and accrued liabilities, affiliated companies		(51.3	)		7.5
			Other current liabilities		12.2			31.3
			Long-term receivables and payables, affiliated companies		(44.1	)		(38.5	)
			Other		(36.7	)		(22.4	)
	Net cash provided by operating activities				143.8			5.9
Cash Flows From Investing Activities
	Utility construction expenditures (excluding equity portion of allowance for funds used during construction)				(319.0	)		(264.6	)
	Change in cash pool at parent				15.3			(201.2	)
	Sales of investments and other assets				12.9			—
	Increase in restricted funds				(5.4	)		(21.1	)
	Net cash used in investing activities				(296.2	)		(486.9	)
Cash Flows From Financing Activities
	Proceeds from issuance of short-term borrowings				189.0			—
	Proceeds from issuance of long-term debt				400.0			623.2
	Repayment of long-term debt				(259.5	)		(124.8	)
	Debt issuance costs				(2.5	)		—
	Preference stock dividends paid				(9.9	)		(9.9	)
	Distribution to parent				(171.7	)		—
	Net cash provided by financing activities				145.4			488.5
Net (Decrease) Increase in Cash and Cash Equivalents					(7.0	)		7.5
Cash and Cash Equivalents at Beginning of Period					17.6			10.9
Cash and Cash Equivalents at End of Period				$	10.6		$	18.4

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

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Basis of Presentation

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

Reclassifications

We have reclassified certain prior-period amounts:

•

Derivative assets and liabilities as of December 31, 2007 reflect the adoption of Staff Position FIN 39-1, Amendment of FASB Interpretation No. 39, on January 1, 2008. We discuss the adoption of Staff Position FIN 39-1 in more detail beginning on page 30.

•

We have separately presented "Restricted cash" that was previously reported within "Other current assets" on BGE's Consolidated Balance Sheet.

•

We have separately presented "Amortization of nuclear fuel," "Amortization of energy contracts," and "All other amortization" that were previously reported within "Depreciation, depletion, and amortization" on our Consolidated Statements of Cash Flows.

•

We have separately presented "Net collateral and margin" that was previously reported within other working capital accounts on our Consolidated Statements of Cash Flows.

•

Revenues and fuel and purchased energy expenses for the nine months ended September 30, 2008 were decreased by $321.0 million to reflect a prior period misclassification that had no impact on gross margin.

•

We have separately presented "Other amortization" that was previously reported within "Depreciation and amortization" on BGE's Consolidated Statements of Cash Flows.

Pending Merger with MidAmerican Energy Holdings Company

On September 19, 2008, Constellation Energy entered into an Agreement and Plan of Merger with MidAmerican Energy Holdings Company (MidAmerican) under which MidAmerican will acquire Constellation Energy for $26.50 per common share. As a result, upon closing of the transaction, Constellation Energy will become a wholly owned subsidiary of MidAmerican.

        In connection with the merger transaction, on September 22, 2008, Constellation Energy issued 10,000 shares of 8% Series A Convertible Preferred Stock (Preferred Stock) of Constellation Energy to MidAmerican for an aggregate purchase price of $1 billion. We discuss this Preferred Stock in more detail beginning on page 21.

        The merger agreement has been approved by both companies' boards of directors, but completion of the merger is contingent upon, among other things:

•

the absence of a material adverse effect on Constellation Energy from the date of the merger agreement,

•

all unsecured senior debt of Constellation Energy being rated investment grade or better with no less than a stable outlook,

•

if requested by MidAmerican, the receipt of payoff letters from lenders under Constellation Energy's credit facilities or the receipt of a waiver from such lenders of any default under the credit facilities as a result of the merger,

•

MidAmerican not having determined that the economic value of Constellation Energy's retail and/or wholesale businesses or assets, taken as a whole, have materially deteriorated since June 30, 2008 (the merger agreement provides that an adverse change in the net economic value of such businesses or assets in excess of $400 million since June 30, 2008 will be deemed material),

•

approval of the transaction by shareholders of Constellation Energy, and

•

receipt of required regulatory approvals.

        The parties are working to complete the merger in the second quarter of 2009. The merger agreement may be terminated by either party if the merger does not occur by June 19, 2009 (or September 19, 2009 if all conditions other than those relating to regulatory approvals, debt ratings, and/or required consents have been fulfilled as of June 19, 2009). We discuss our risk factors associated with this merger in the Risk Factors section beginning on page 68.

        The merger agreement contains certain termination rights for both Constellation Energy and MidAmerican. If

11

the merger agreement is terminated for any reason other than a breach of the merger agreement by MidAmerican:

•

Constellation Energy will be required to pay MidAmerican a termination fee of $175 million; and

•

The Preferred Stock will automatically convert into $1 billion aggregate principal amount of 14% Senior Notes of Constellation Energy and either 35,506,757 shares of our common stock (equivalent to 19.9% of the outstanding common shares as of September 22, 2008) or, if regulatory approvals necessary to issue the shares have not been received, the number of shares that may be issued plus a cash payment equivalent to the $26.50 merger price per share multiplied by the the portion of the total shares that could not be issued because all necessary regulatory approvals had not been received.

        In addition, the Preferred Stock will automatically convert as set forth above if the merger is not completed by June 19, 2009 (which may be extended to September 19, 2009).

        Constellation Energy has agreed that the maximum aggregate liability of MidAmerican for losses or damages in connection with the merger agreement would be limited to $1 billion. Our recourse for such losses or damages is limited to the Preferred Stock issued to MidAmerican or the shares of Constellation Energy common stock and $1 billion in senior notes issued upon conversion of the Preferred Stock or the proceeds of the redemption or repayment of the Preferred Stock or senior notes. In addition, if Constellation Energy attempts to challenge the validity of the $1 billion damage cap, such amount is automatically reduced to $1,000.

Merger and Strategic Alternatives Costs

We incurred costs during the quarter ended September 30, 2008 related to our pending merger with MidAmerican and our pursuit of other strategic alternatives to the merger with MidAmerican. These costs totaled $39.2 million pre-tax, including a payment of $25 million to MidAmerican, of which BGE recorded $11.1 million. A significant portion of these costs are not tax deductible, and BGE will not seek recovery of these costs in regulated electric and gas service rates.

Impairments and Other Costs

Impairment Evaluations

We discuss our evaluations of assets for impairment and other than temporary declines in value in the Significant Accounting Policies section of our 2007 Annual Report on Form 10-K. We perform impairment evaluations for our long-lived assets, equity method investments, nuclear decommissioning trust assets, and goodwill when triggering events occur that would indicate that the potential for an impairment exists.

        In addition, Statement of Financial Accounting Standards (SFAS) No. 142, Goodwill and Other Intangible Assets requires goodwill to be evaluated for impairment on an annual basis regardless of whether any triggering events have occurred. Our accounting policy is to perform that annual impairment review in the third quarter of each year.

        During the third quarter of 2008, the following triggering events resulted in the need for us to perform impairment analyses:

•

We announced a strategic initiative to sell our upstream gas assets.

•

There was a significant decline in the availability of credit in the markets.

•

There was a significant decline in the overall stock market and, in particular, our stock price.

•

We signed a definitive merger agreement with MidAmerican.

•

Commodity prices declined substantially.

        As a result of these evaluations, we recorded impairments of our upstream gas assets, goodwill, and certain investments in debt and equity securities. We describe the impairment evaluations we performed in the following sections.

Long-Lived Assets

We evaluate potential impairment of long-lived assets classified as held for use under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which provides that an impairment loss shall be recognized if the carrying amount of such assets is not recoverable. The carrying amount of an asset held for use is not recoverable if it exceeds the total undiscounted future cash flows expected to result from the use and eventual disposition of the asset.

        This evaluation requires us to estimate uncertain future cash flows. In order to estimate future cash flows, we consider historical cash flows and changes in the market environment and other factors that may affect future cash flows. The assumptions we use are consistent with forecasts that we make for other purposes (for example, in preparing our other earnings forecasts) or have been adjusted to reflect relevant subsequent changes. If we are considering alternative courses of action (such as the potential sale of an asset), we probability-weight the alternative courses of action to estimate the expected cash flows.

        We use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, and operating costs. However, actual

12

future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.

Upstream Gas Properties

During the third quarter of 2008, we performed impairment analyses for our upstream gas properties as a result of the following triggering events:

•

We announced our intent to sell our upstream gas assets.

•

There was a significant decrease in natural gas prices and oil prices from June 30, 2008 to September 30, 2008.

        We evaluate proved properties under SFAS No. 144. We evaluate unproved property under SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Properties. Unproved property is impaired if there are no firm plans to continue drilling, lease expiration is at risk, or historical experience necessitates a valuation allowance. To the extent that unproved property is part of an asset that contains proved property, the accounting guidance under SFAS No. 144 applies for evaluating impairment.

        While we have begun the process necessary to sell these properties, we have not yet obtained the formal approval of our board of directors, which is required to commit to a plan for sale. As a result, we continue to classify these properties as held for use as of September 30, 2008. Accordingly, our impairment evaluation consisted of estimating expected undiscounted cash flows and comparing those amounts to the carrying value.

        We evaluated our upstream gas portfolio for impairment at the individual property level, which is the lowest level of identifiable cash flows, since each property has separate financial statements identifying and capturing the related cash flows. We evaluated a combination of cash flows from operations scenarios for the remaining period for which we expect to hold these properties as well as estimates of proceeds from each property's ultimate disposal. The primary inputs to our estimates of cash flows from operations were natural gas and oil prices based upon forward curves and modeled data for unobservable periods. The primary inputs to our estimate of proceeds from disposal were a combination of external market bids, internal models and reserve reports, and information from external advisors assisting in the sale of these assets. We maximized the use of market information to the extent it was available. We evaluated several possible courses of action and timing, and we probability-weighted the cash flows associated with each of these scenarios based upon our best estimates of the expected outcome and timing in order to arrive at each property's expected future cash flows.

        Our evaluation indicated that estimated cash flows were less than the carrying value of three of our seven upstream gas properties. The primary factor leading to the decline in expected cash flows was the decrease in market prices for natural gas and oil during the third quarter of 2008 combined with our expectation that we would sell these properties rather than hold them for their full useful lives. As a result, we recorded an approximately $143 million pre-tax impairment charge during the quarter ended September 30, 2008 to write-down each impaired property's carrying value to fair value. The asset groups impaired include our interest in proved and unproved crude oil and natural gas reserves in south Texas of $62.6 million, proved natural gas reserves in the Rocky Mountains of $73.2 million, and proved and unproved natural gas reserves in the Offshore-Gulf of Mexico of $7.1 million.

        We recorded the total impairment charge in the "Impairments and Other Costs" line in our Consolidated Statements of Income (Loss), and it is reported in our merchant energy business results. The impairment charge for our interest in the Rocky Mountains natural gas reserves was offset partially by reclassifying cash-flow hedges with a pre-tax net gain deferred in "Accumulated other comprehensive loss" of $4.5 million into "Nonregulated revenues" in the Consolidated Statements of Income (Loss).

Debt and Equity Securities

We evaluated certain of our investments in debt and equity securities (both equity-method and cost-method investments) in light of recent declines in market prices, particularly during the month of September 2008. The investments we evaluated include our investment in Constellation Energy Partners LLC (CEP), our nuclear decommissioning trust fund assets, and our investment in UniStar Nuclear Energy (UNE). We record an impairment if an investment has experienced a decline in fair value to a level less than our carrying value and the decline is "other than temporary." We do not record an impairment if the decline in value is temporary and we have the ability and intent to hold the investment until its value recovers.

        In making this determination, we evaluate the reasons for an investment's decline in value, the extent and length of that decline, and factors that indicate whether and when the value will recover. For securities held in our nuclear decommissioning trust fund for which the market value is below book value, the decline in fair value for these securities is considered other than temporary and we write them down to fair value.

        As of September 30, 2008, the fair value of our investment in CEP based upon its closing unit price was $73 million, which was lower than its carrying value of $128 million. The fair value of our investment fell below

13

carrying value at the end of August, continued to decline through the end of September, and has further declined during October. While CEP's estimate of net asset value exceeds our carrying value, the decline in fair value of our investment in CEP reflects a number of other factors, including:

•

turmoil and tightening in the financial and credit markets in the United States,

•

substantial decreases in the market price of natural gas and oil,

•

the effect of these factors on market perceptions of gas exploration and production master limited partnerships, and

•

factors related to Constellation Energy's financial condition and possible sale of its investment in CEP.

        As a result of evaluating these factors, we determined that the decline in the value of our investment is other than temporary. Therefore, we recorded an approximately $55 million pre-tax impairment charge during the quarter ended September 30, 2008 to write-down our investment to fair value as of that date. We recorded this charge in "Impairments and other costs" in our Consolidated Statements of Income (Loss). To the extent that the market price of our investment declines further in future quarters, we may record additional write-downs if we determine that those additional declines are other than temporary.

        As a result of significant declines in the stock market during the third quarter of 2008, the fair values of several of the securities held in our nuclear decommissioning trust fund declined below book value. As a result, we recorded an approximately $31 million pre-tax impairment charge in the "Other (expense) income" line in our Consolidated Statements of Income (Loss). In addition, we recorded other changes in the fair value of our nuclear decommissioning trust fund assets that are not impaired in other comprehensive income.

        We also evaluated the impact of the events that occurred in the third quarter of 2008 on the recoverability of our investment in UNE. Based upon our consideration of these events and the status of UNE's activities, we determined that our investment in UNE is not impaired as of September 30, 2008.

        The estimates we utilize in evaluating impairment of our debt and equity securities require judgment and the evaluation of economic and other factors that are subject to variation, and the impact of such variations could be material.

Goodwill

Goodwill is the excess of the purchase price of an acquired business over the fair value of the net assets acquired. We account for goodwill and other intangibles under the provisions of SFAS No. 142. SFAS No. 142 requires us to evaluate goodwill for impairment at least annually or more frequently if events and circumstances indicate the business might be impaired. Goodwill is impaired if the carrying value of the business exceeds fair value. Annually, in the third quarter of each year, we evaluate goodwill for impairment.

        The primary judgment affecting our impairment evaluation is the requirement to estimate fair value of the reporting units to which the goodwill relates. We evaluate impairment at the reportable segment level, which is the lowest level in the organization that constitutes a business for which discreet financial information is available.

        Substantially all of our goodwill relates to our merchant energy segment. The lack of observable market prices for the merchant energy segment requires us to estimate fair value, which we determined on a preliminary basis using the income valuation approach by computing discounted cash flows, consistent with prior evaluations. Although our estimate of discounted cash flows exceeded the carrying value of the merchant energy segment, because our common stock continued to trade at a price less than carrying value for the entire company throughtout the last half of September and all of October, we also estimated fair value for the merchant energy segment using current market price information.

        The primary inputs and assumptions to our estimate of fair value based upon market information were as follows:

•

the fair value of Constellation Energy based upon recent market prices of our common stock,

•

the estimated fair value of BGE, and

•

the estimated value of the agreements executed with MidAmerican.

        Using this information, we deducted the estimated fair value of non-merchant energy segment businesses from the fair value of Constellation Energy as a whole in order to estimate the fair value of the merchant energy segment. Based upon this estimate, the fair value of the merchant energy segment was substantially less than its carrying value. The primary difference between this estimate and our modeled estimates using the discounted cash flow income approach is that the market price approach incorporates the market's valuation discount associated with our merchant energy segment due to its significant liquidity and collateral requirements. We believe that this is a more appropriate method for estimating fair value as of the end of September 2008 than the modeled valuation techniques because it incorporates observable market information to a greater extent, which reflects current market conditions, and

14

because it requires fewer and less subjective judgments and estimates than our modeled estimates.

        As a final consideration, we also evaluated the circumstances surrounding MidAmerican's purchase of Constellation Energy and whether the current market price of our common stock should be considered to represent fair value for accounting purposes. While the transaction price for the purchase of Constellation Energy resulted from negotiations that occurred over an abbreviated period of time during which the Company was experiencing financial difficulty, ongoing trading of the stock at levels approximating the transaction price represents the market's present assessment of fair value in a liquid, active market. This is consistent with recent guidance issued by the SEC Office of the Chief Accountant and FASB Staff on the determination of fair value in distressed markets.

        Based on our evaluation of these alternative measures of fair value, we determined that the fair value of the merchant energy business segment is less than its carrying value. Therefore, in order to measure the potential impairment of goodwill, we estimated the fair value of the merchant energy segment's assets and liabilities. We determined that the fair value of its assets net of liabilities substantially exceeds the segment's total fair value, indicating that the merchant energy segment's goodwill is impaired as of September 30, 2008. Accordingly, we recorded a pre-tax charge of approximately $265 million to write-off the entire balance of our merchant energy segment goodwill as of September 30, 2008. This charge is recorded in "Impairments and other costs" in our Consolidated Statements of Income (Loss).

Other Costs

In September 2008, we entered into a non-binding agreement to settle a class action complaint that alleged a subsidiary's ash placement operations at a third party site damaged surrounding properties. As a result of this agreement, we estimated and recorded a $15 million pre-tax charge net of an expected insurance recovery during the quarter ended September 30, 2008.

Variable Interest Entities

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

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

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

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

	Power Contract Monetization VIEs		All Other VIEs		Total
	(In millions)
Total assets	$	673.0	$	394.0	$	1,067.0
Total liabilities		529.7		216.5		746.2
Our ownership interest		—		48.1		48.1
Other ownership interests		143.3		129.4		272.7
Our maximum exposure to loss		48.4		224.2		272.6

        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, 2008 consists of the following:

•

outstanding receivables, loans and letters of credit totaling $222.5 million,

•

the carrying amount of our investments totaling $48.1 million, and

•

debt and performance guarantees totaling $2.0 million.

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

15

Workforce Reduction Costs

We incurred costs related to workforce reduction efforts initiated at our nuclear generating facilities in 2006 and 2007. We discuss these costs in more detail in Note 2 of our 2007 Annual Report on Form 10-K. We substantially completed both of these workforce reduction efforts during 2008.

        In September 2008, our merchant energy business approved a restructuring of the workforce at our Customer Supply operations. We recognized a liability of $2.2 million pre-tax during the quarter ended September 30, 2008 related to the elimination of approximately 100 positions associated with this restructuring. The restructuring is expected to be completed within the next 12 months.

Earnings Per Share

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

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

	Quarter Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(In millions)
Non-dilutive stock options		2.6		—		1.5		—
Dilutive common stock equivalent shares		1.1		2.3		1.7		2.3

As a result of the Company incurring a loss for the quarter ended September 30, 2008, diluted common stock equivalent shares were not included in calculating diluted EPS.

        The $1 billion in Preferred Stock issued to MidAmerican on September 22, 2008, is convertible into Constellation Energy's common stock as discussed in more detail beginning on page 21. This conversion feature did not impact our diluted earnings per share for the quarter ended September 30, 2008, but it will impact our diluted earnings per share in future periods.

Accretion of Asset Retirement Obligations

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

	(In millions)
Liability at January 1, 2008	$	917.6
Accretion expense		50.8
Liabilities incurred		1.0
Liabilities settled		(0.6	)
Revisions to cash flows		2.0
Other		(0.2	)
Liability at September 30, 2008	$	970.6

Acquisitions

Hillabee Energy Center

On February 14, 2008, we acquired the Hillabee Energy Center, a partially completed 774MW gas-fired combined cycle power generation facility located in Alabama for $156.9 million (including direct costs), which we accounted for as an asset acquisition. We allocated the purchase price primarily to the equipment with lesser amounts allocated to land and contracts acquired. We plan to complete the construction of this facility and expect it to be ready for commercial operation in late 2009.

West Valley Power Plant

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

Nufcor International Limited

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

        We acquired 100% ownership of Nufcor for $102.8 million, including direct costs, of which $104.9 million was paid in cash at closing. Subsequent to

16

closing, we received $3.1 million back from the seller as a result of adjustments to Nufcor's net assets. As part of the purchase, we acquired $37.3 million in cash.

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

At June 26, 2008
	(In millions)
Cash	$	37.3
Fuel stocks		126.8
Other current assets		8.5
Total current assets		172.6
Goodwill(1)(2)		6.3
Other assets		30.4
Total assets acquired		209.3
Short-term borrowings		(28.0	)
Unamortized energy contract liabilities		(15.8	)
Other current liabilities		(29.7	)
Total current liabilities		(73.5	)
Unamortized energy contract liabilities		(33.0	)
Total liabilities		(106.5	)
Net assets acquired	$	102.8

(1) Not deductible for tax purposes.
(2) Amount has been subsequently charged to expense as part of our merchant energy goodwill impairment charge recorded during the third quarter of 2008.

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

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

        In connection with efforts to improve our liquidity, we announced strategic initiatives that included the sale of our international business, including Nufcor. We discuss our strategy in more detail on page 21.

Asset Sales

Working Interests in Gas Producing Fields

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

        In addition, on March 31, 2008, we sold our working interest in certain oil and natural gas producing properties to CEP, a related party, and recognized a gain of $14.3 million, net of the minority interest gain of $0.7 million. We discuss this transaction in more detail on page 34.

        These gains are included in "Gains on Sales of Assets" line in our Consolidated Statements of Income (Loss).

Dry Bulk Vessel

On July 10, 2008, a shipping joint venture, in which our merchant energy business has a 50% ownership interest, sold one of the six dry bulk vessels it owns. Our merchant energy business recognized a $29.0 million pre-tax gain on this sale. The gain is included in "Nonregulated revenues" line in our Consolidated Statements of Income (Loss).

Emissions Allowances

The Clean Air Interstate Rule (CAIR) required states in the eastern United States to reduce emissions of sulfur dioxide (SO₂) and established a cap-and-trade program for annual nitrogen oxides (NO_x) emission allowances. On July 11, 2008, the United States Court of Appeals for the D.C. Circuit (the "Court") issued an opinion vacating CAIR, subject to a 45 day delay during which parties may petition for rehearing. This delay was extended for an additional 30 days and on September 24, 2008 the Environmental Protection Agency (EPA) filed a petition for rehearing. On October 21, 2008, the Court asked for parties to submit supporting arguments on the EPA's petition for rehearing. Furthermore, the Court specifically requested briefing on whether any party is requesting that CAIR be revoked, and whether the Court should stay its mandate until the EPA issues a revised rule.

        Since the mandate has not yet been issued, the EPA continues to operate the trading system for SO₂ and annual NO_x emission allowances in accordance with CAIR. Trading of SO₂ allowances will continue even if the Court issues a mandate. However, due to the ongoing uncertainty caused by the Court's July 11, 2008 decision, market prices for SO₂ and annual NO_x allowances are lower than they were prior to the Court's decision.

        We account for our emission allowance inventory at the lower of cost or market, which includes consideration of our expected requirements related to the future generation of electricity. The weighted-average cost of our current-year SO₂ allowance inventory in excess of amounts needed to satisfy these requirements was greater than market value at June 30, 2008 and market prices decreased further for both SO₂ and annual NO_x emission allowances through September 30, 2008. After giving consideration to the Court's decision and the subsequent decline in the market price of these allowances, we recorded a write-down of our SO₂ allowance inventory totaling $22.1 million

17

pre-tax to reflect the June 30, 2008 market price. At September 30, 2008, we recorded an additional write-down of our SO₂ emission allowance inventory and recorded a write-down of our annual NO_x emission allowance inventory of $58.9 million to reflect market prices at September 30, 2008. The write-down was recorded in the "Nonregulated revenues" line in our Consolidated Statements of Income (Loss). This write-down was partially offset by mark-to-market gains in the quarter ended September 30, 2008 of $22.2 million pre-tax on derivative contracts for the forward sale of emission allowances. This gain reflects the impact of lower market prices on the value of those derivative contracts.

        The ultimate amount of any additional losses will be determined based on future market prices, which could vary materially from current market price levels, and could be affected by the ultimate resolution of the proceedings before the Court. At this time, we cannot predict the outcome of the EPA petition for rehearing or any further judicial, regulatory or legislative developments that might result in some or all of the provisions of CAIR being preserved. If any of these developments were to occur prior to December 31, 2008, the market prices of SO₂ and annual NO_x allowances may recover and the write-down of our inventory of allowances and contracts for the forward sale of annual NO_x allowances may be reduced or avoided. As a result, these developments could have a material impact on our financial results.

Information by Operating Segment

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

•

Our merchant energy business is nonregulated and includes:

—

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

—

structured transactions and risk management services for various customers (including hedging of output from generating facilities and fuel costs),

—

deployment of risk capital through portfolio management and trading activities,

—

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

—

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

—

upstream (exploration and production) and downstream (transportation and storage) natural gas operations,

—

coal sourcing and logistics services and uranium marketing services for the variable or fixed supply needs of global customers, and

—

generation operations and maintenance.

•

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

•

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

        Our remaining nonregulated businesses:

•

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

•

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

•

develop and deploy new nuclear plants in North America.

        In connection with efforts to improve our liquidity, we have announced strategic initiatives including the sale of our upstream gas properties, our international business, which includes our coal sourcing, freight, uranium, power, natural gas and emissions marketing activities outside the United States, and our gas trading activities. We discuss these strategies and their effect on liquidity on page 21.

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

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	Reportable Segments
	Merchant Energy Business			Regulated Electric Business			Regulated Gas Business			Other Nonregulated Businesses			Eliminations			Consolidated
	(In millions)
For the three months ended September 30,
2008
Unaffiliated revenues	$	4,300.8		$	822.3		$	150.3		$	50.2		$	—		$	5,323.6
Intersegment revenues		191.8			0.1			5.2			—			(197.1	)		—
Total revenues		4,492.6			822.4			155.5			50.2			(197.1	)		5,323.6
Net (loss) income		(246.0	)		31.7			(12.2	)		0.8			—			(225.7	)
2007
Unaffiliated revenues	$	4,910.4		$	778.2		$	112.8		$	55.0		$	—		$	5,856.4
Intersegment revenues		365.5			—			5.9			—			(371.4	)		—
Total revenues		5,275.9			778.2			118.7			55.0			(371.4	)		5,856.4
Income from discontinued operations		0.7			—			—			—			—			0.7
Net income (loss)		227.2			34.3			(9.8	)		(0.3	)		—			251.4
For the nine months ended September 30,
2008
Unaffiliated revenues	$	12,011.9		$	1,980.3		$	724.4		$	175.3		$	—		$	14,891.9
Intersegment revenues		707.8			0.2			15.6			0.2			(723.8	)		—
Total revenues		12,719.7			1,980.5			740.0			175.5			(723.8	)		14,891.9
Net income (loss)		105.9			(38.8	)		24.1			0.3			—			91.5
2007
Unaffiliated revenues	$	13,157.6		$	1,837.3		$	674.4		$	174.5		$	—		$	15,843.8
Intersegment revenues		956.1			—			14.4			—			(970.5	)		—
Total revenues		14,113.7			1,837.3			688.8			174.5			(970.5	)		15,843.8
Loss from discontinued operations		(0.9	)		—			—			—			—			(0.9	)
Net income		449.4			85.9			18.2			9.9			—			563.4

Certain prior-period amounts have been reclassified to conform with the current period's presentation. Revenues for the nine months ended September 30, 2008 reflect the reclassification of $321 million relating to the three months ended June 30, 2008 to conform with the current period presentation. We discuss our reclassifications in more detail on page 11 of the Notes to Consolidated Financial Statements.

Total assets increased approximately $1.6 billion during 2008. Most of the increase relates to our merchant energy segment assets and is primarily due to an $820 million increase in derivative assets and an $843 million increase in property, plant and equipment. We discuss the increase in derivative assets in more detail on page 32 of the Notes to the Consolidated Financial Statements.

Our merchant energy operating results for the quarter ended September 30, 2008 include the following after-tax charges: impairments and other costs of $298.8 million, net emission allowance write-down of $22.8 million, and an impairment charge of our nuclear decommissioning trust assets of $15.3 million.

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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,
	2008			2007			2008			2007
	(In millions)
Components of net periodic pension benefit cost
Service cost	$	14.6		$	13.3		$	42.4		$	38.0
Interest cost		26.6			25.6			76.8			72.9
Expected return on plan assets		(29.6	)		(27.8	)		(85.5	)		(79.1	)
Recognized net actuarial loss		6.6			8.7			19.0			25.1
Amortization of prior service cost		2.8			1.4			8.3			4.0
Amount capitalized as construction cost		(2.3	)		(2.9	)		(7.1	)		(8.8	)
Net periodic pension benefit cost1	$	18.7		$	18.3		$	53.9		$	52.1

1 BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $4.5 million for the quarter ended September 30, 2008 and $5.8 million for the quarter ended September 30, 2007. BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $13.2 million for the nine months ended September 30, 2008 and $16.1 million for the nine months ended September 30, 2007.

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

	Quarter Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In millions)
Components of net periodic postretirement benefit cost
Service cost	$	1.3		$	1.6		$	4.9		$	5.1
Interest cost		5.4			5.7			19.3			19.0
Amortization of transition obligation		0.5			0.4			1.7			1.6
Recognized net actuarial loss		0.5			1.0			1.6			3.2
Amortization of prior service cost		(0.8	)		(0.8	)		(2.8	)		(2.7	)
Amount capitalized as construction cost		(1.5	)		(1.7	)		(5.5	)		(6.0	)
Net periodic postretirement benefit cost1	$	5.4		$	6.2		$	19.2		$	20.2

1 BGE's portion of our net periodic postretirement benefit cost, excluding amounts capitalized, was $3.3 million for the quarter ended September 30, 2008 and $3.7 million for the quarter ended September 30, 2007. BGE's portion of our net periodic postretirement benefit costs, excluding amounts capitalized, was $11.0 million for the nine months ended September 30, 2008 and $11.9 million for the nine months ended September 30, 2007.

        Our non-qualified pension plans and our postretirement benefit programs are not funded; however, we have trust assets securing certain executive pension benefits. We estimate that we will incur approximately $10 million in pension benefit payments for our non-qualified pension plans and approximately $29 million for retiree health and life insurance benefit payments during 2008. We contributed $76 million to our qualified pension plans in March 2008 and there is no requirement to contribute additional amounts in 2008.

Financing Activities

Credit Facilities

Constellation Energy had bank lines of credit under facilities totaling $5.7 billion at September 30, 2008 for short-term financial needs. These facilities can issue letters of credit, commercial paper, and/or cash borrowings up to approximately $5.7 billion. At September 30, 2008, we had $4.0 billion in letters of credit issued and borrowed $750.0 million against one of the credit facilities. At the end of October 2008 we estimate that we had $4.0 billion in letters of credit issued under these facilities and $750.0 million borrowed. In addition, at September 30, 2008, we had $310.5 million in commercial paper outstanding and at the end of October 2008 we had approximately $17 million in commercial paper outstanding under these facilities.

        At September 30, 2008, BGE had a $400.0 million five-year revolving credit facility expiring in 2011. BGE can borrow directly from the banks, use the facility to allow commercial paper to be issued or issue letters of credit. As of September 30, 2008, BGE had $1.1 million in letters of credit issued under this facility. As of October 31, 2008, BGE had $1.1 million in letters of credit issued and borrowed $270.0 million against the facility. In addition, at September 30, 2008 BGE had $189.0 million in commercial paper outstanding and at the end of October 2008 BGE had approximately $18 million in commercial paper outstanding.

        Total estimated net available liquidity as of October 31, 2008 was as follows:

	Constellation Energy			BGE			Total Consolidated
	(In millions)
Credit facilities	$	5,730		$	400		$	6,130
Less: Letters of credit issued		(3,977	)		(1	)		(3,978	)
Less: Cash drawn on credit facilities		(750	)		(270	)		(1,020	)
Undrawn facilities		1,003			129			1,132
Less: Commercial paper outstanding		(17	)		(18	)		(35	)
Net available facilities		986			111			1,097
Add: Cash		719			59			778
Net available liquidity	$	1,705		$	170		$	1,875

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        Constellation Energy has credit facilities totaling $1.38 billion that will expire before December 31, 2008. We anticipate closing in November 2008 on a new credit facility of approximately $1.2 billion. In early November 2008, we also executed agreements with MidAmerican that provide us the option to sell one or both of the following assets to MidAmerican for aggregate proceeds of $350 million:

•

our equity interest in Safe Harbor Water Power Corporation, a 417 MW hydroelectric generating facility located in Pennsylvania, and

•

our West Valley generating plant, a 200 MW electric generating facility located in Utah.

        The agreements are expected to become effective by November 14, 2008, provided that MidAmerican has approved certain disclosure schedules related to each agreement, and expire upon the earlier of the sale of the assets, the closing of the merger, or November 6, 2009.

        Upon exercise of an option, Constellation Energy's subsidiary will enter into a purchase agreement for the sale of the asset to MidAmerican and Constellation Energy will guarantee its subsidiary's obligations under the purchase agreement. The closing of the sale, including payment of the purchase price to Constellation Energy, will be subject to customary closing conditions, including receipt of required regulatory approvals.

        In addition to these efforts, we are actively seeking to increase available liquidity and to reduce our business risk. Specifically, we are reducing capital spending and ongoing expenses, scaling down the expected variability in long-term earnings and short-term collateral usage, and limiting our exposure to business activities that require contingent capital support. We have announced strategic initiatives including efforts to sell our upstream gas properties, our international business, which includes our coal sourcing, freight, uranium, power, natural gas and emissions marketing activities outside North America, and our gas trading activities.

        Collectively, we believe these efforts will provide sufficient liquidity to manage our business and successfully close the pending merger with MidAmerican. However, if market factors prevent us from successfully executing our plan or we are otherwise unable to successfully execute our plan, our liquidity would be adversely affected, which would have a material adverse effect on our business, results of operations, and financial condition.

Debt

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

•

Issued $250.0 million of Zero Coupon Senior Notes due June 2023. Interest, compounded semi-annually, will be paid at maturity or when redeemed. The yield on these notes based on the original maturity date of June 2023 is 6.96%. These notes include a put option, which allows the holder to sell the notes back to us on the put option dates at a price equal to the principal amount plus accrued interest. The put option dates commence in June 2010 and occur yearly at that time through maturity, except for 2012 and 2015. As a result of the put option feature, these notes will be classified as a current liability beginning in June 2009.

•

Issued $450.0 million of Series A Junior Subordinated Debentures at 8.625% due June 15, 2063, but which can be automatically extended to no later than June 15, 2068 at our discretion. Interest is payable quarterly in March, June, September, and December. However, we may choose at any time to defer interest payments on these debentures for up to ten consecutive years. During this deferral period, interest will continue to accrue, compounded quarterly, and the deferred interest payments will accrue additional interest at a rate equal to the interest rate on these debentures.

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

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

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

Mandatorily Redeemable Convertible Preferred Stock

On September 19, 2008, Constellation Energy entered into an Agreement and Plan of Merger with MidAmerican. We discuss the merger agreement in more detail beginning on page 11. In connection with the merger agreement, Constellation issued 10,000 shares of 8% Series A Convertible Preferred Stock of Constellation Energy (Preferred Stock) to MidAmerican for $1 billion. The Preferred Stock is mandatorily redeemable on

21

September 22, 2010 for an amount in cash equal to 100% of the stated value, subject to adjustments, plus all accrued but unpaid dividends.

        Because of the mandatory redemption provision, the Preferred Stock will be accounted for as debt and included in the "Long-term debt, net of current portion" line on our Consolidated Balance Sheets. Dividends will be included in the "Interest expense" line on our Consolidated Statements of Income (Loss).

        If the merger agreement is terminated for any reason other than a breach of the agreement by MidAmerican or the merger is not completed by June 19, 2009 (which may be extended to September 19, 2009), the Preferred Stock will automatically convert into $1 billion aggregate principal amount of 14% Senior Notes of Constellation Energy and either:

•

35,506,757 shares of our common stock (equivalent to 19.9% of the outstanding common shares as of September 22, 2008) or,

•

if necessary regulatory approvals to issue all 35,506,757 shares of our common stock to a single party have not been received, the number of shares that may be issued plus a cash payment equivalent to the $26.50 merger price per share multiplied by the portion of the total shares that could not be issued because all necessary regulatory approvals had not been received. Prior to the receipt of approval of the FERC, a cash payment would be required in lieu of the issuance of shares that are otherwise due to MidAmerican in excess of 10% of the total shares outstanding.

        We determined that the conversion provisions requiring a combination of a cash payment and issuance of up to 35.5 million shares of common stock upon a cancellation of the merger agreement constitute an embedded derivative that must be bifurcated from the Preferred Stock and recorded at fair value with changes in fair value recorded in earnings. Accordingly, we recorded a current derivative liability of approximately $46.2 million as the fair value of this conversion feature as of September 30, 2008 and we recorded a corresponding discount on the Preferred Stock. We will amortize the discount to interest expense as an additional dividend cost on the Preferred Stock over its term using the effective interest method.

        Determining the fair value of this derivative required the exercise of judgment because it is an embedded provision in a nonderivative host contract, is not traded on any market, and its value is dependent upon certain inputs that are not observable in any market. The primary factor affecting the fair value is the estimate of the probability that the merger may be cancelled.

        We estimated the merger cancellation discount using market information by comparing the merger purchase price per share, adjusted for the time value of money prior to closing of the transaction, to the average market price of our common stock for the five day period after the public announcement that another potential bidder was no longer seeking to acquire the company. We considered this period appropriate for estimating this input because we believe that it reflects a value for our common stock that primarily incorporates the risk of cancellation of the merger and the time value of money. This valuation methodology incorporates an assumption that a market-derived merger cancellation probability is 5% for the purpose of determining the fair value of the derivative.

        The fair value of this derivative could change substantially based upon discrete factors. The primary factors that could change its value, other than the passage of time and changes in interest rates, are:

•

approval or denial of approval of the merger by shareholders or various regulatory bodies,

•

the existence and amount of any potential competing bid for the company, and

•

changes in the market price of our common stock.

        It is not possible to predict whether these events could occur, but if and when they do, the estimated fair value of the derivative could increase or decrease substantially, and such changes would be recorded in earnings when they occur. Upon receipt of all approvals necessary to issue 19.9% of the shares of our common stock to a single party, the derivative will be considered an equity instrument, and we will reclassify the fair value at that time to common shareholders' equity and discontinue recording changes in its fair value, in accordance with SFAS No. 133. At that time, the potential issuance of equity will be considered in determining diluted shares outstanding and diluted earnings per share.

        So long as any shares of the Preferred Stock are outstanding, Constellation Energy and its subsidiaries may not, without the consent of holders of at least a majority of then outstanding shares of Preferred Stock, undertake certain actions. Such actions include incurring indebtedness of Constellation Energy other than senior unsecured debt ranking equally with existing senior unsecured debt of Constellation Energy and of BGE other than indebtedness consistent with past practices and regulatory approvals.

        If issued, the Senior Notes will accrue interest at 14% per year, payable monthly in cash. These Senior Notes would mature and become due on December 31, 2009. The Senior Notes also contain restrictions on the conduct of Constellation Energy's business including limitations on:

•

indebtedness;

•

incurring certain liens;

•

engaging in certain fundamental changes of Constellation Energy;

•

the sale of assets;

•

certain types of restricted payments;

•

investments, loans and advances;

•

acquisitions and transactions with affiliates;

22

•

optional payments and modifications to debt instruments; and

•

the issuance of capital stock.

        The proceeds from the Preferred Stock issuance will be used for general corporate purposes.

Maryland Settlement Agreement

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

•

Each party acknowledged that the agreements adopted in 1999 relating to Maryland's electric restructuring law are final and binding and the Maryland PSC will close ongoing proceedings relating to the 1999 settlement.

•

BGE will provide its residential electric customers approximately $188 million in the form of a one-time $170 per customer rate credit by no later than December 31, 2008. We recorded the liability and related charge in the second quarter of 2008 as a current regulatory liability on our and BGE's Consolidated Balance Sheets and a reduction to "Electric revenues" on our and BGE's Consolidated Statements of Income (Loss). BGE issued the credit on customers' September 2008 bills.

•

BGE customers will be relieved of the potential future liability for decommissioning Constellation Energy's Calvert Cliffs Unit 1 and Unit 2, scheduled to occur no earlier than 2034 and 2036, respectively, and will no longer be obligated to pay a total of $520 million, in 1993 dollars adjusted for inflation, pursuant to the 1999 Maryland PSC order regarding the deregulation of electric generation. BGE will continue to collect $18.7 million annually from all electric customers through 2016 for nuclear decommissioning at Calvert Cliffs and continue to rebate this amount to residential electric customers, as previously required by Senate Bill 1, which had been enacted in June 2006.

•

BGE resumed collection of the residential return portion of the Provider of Last Resort (POLR) administrative charge, which had been eliminated under Senate Bill 1, on June 1, 2008 and will continue collection through May 31, 2010 without having to rebate it to residential customers. This will total approximately $40 million over this period. This charge will be suspended from June 1, 2010 through December 31, 2016.

•

Any electric distribution base rate case filed by BGE will not result in increased distribution rates prior to October 2009, and any increase in electric distribution revenue awarded will be capped at 5% with certain exceptions. Any subsequent electric distribution base rate case may not be filed prior to August 1, 2010. The agreement does not govern or affect our ability to recover costs associated with gas rates, federally approved transmission rates and charges, electric riders, tax increases or increases associated with standard offer service power supply auctions.

•

Effective June 1, 2008, BGE implemented revised depreciation rates for regulatory and financial reporting purposes. The revised rates will reduce depreciation expense approximately $22—$24 million annually without impacting rates charged to customers.

•

Effective June 1, 2008, Maryland laws governing investments in companies that own and operate regulated gas and electric utilities were amended to make them less restrictive with respect to certain capital stock acquisition transactions.

•

Constellation Energy elected two independent directors to the Board of Directors of BGE within the required six months from the execution of the settlement agreement.

23

Income Taxes

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

		Quarter Ended September 30,						Nine Months Ended September 30,
		2008			2007			2008			2007
		(In millions)
(Loss) Income before income taxes (excluding BGE preference stock dividends)		$	(334.0	)	$	418.3		$	172.8		$	832.6
Statutory federal income tax rate			35	%		35	%		35	%		35	%
Income taxes computed at statutory federal rate			(116.9	)		146.4			60.5			291.4
(Decreases) increases in income taxes due to:
	Synthetic fuel tax credits flowed through to income		—			(37.1	)		—			(119.7	)
	Synthetic fuel tax credit phase-out		—			20.1			—			44.0
	Synthetic fuel tax credit phase-out true-up from prior periods		—			20.5			(4.6	)		12.6
	Merger-related transaction costs		11.9			—			11.9			—
	State income taxes, net of federal tax benefit		(10.0	)		19.0			13.4			36.6
	Other		3.4			(4.6	)		(9.8	)		(6.5	)
Total income taxes		$	(111.6	)	$	164.3		$	71.4		$	258.4
Effective tax rate			33.4	%		39.3	%		41.3	%		31.0	%

        The changes in our effective tax rate for the quarter and nine months ended September 30, 2008 compared to the quarter and nine months ended September 30, 2007 are primarily due to lower 2008 taxable income increasing the relative impact of the unfavorable tax adjustments on the effective tax rate, the impact of nondeductible merger costs, and the absence of synthetic fuel tax credits, which expired at December 31, 2007.

        BGE's effective tax rate was 43.6% and (69.2%) for the quarter and nine months ended September 30, 2008, respectively, compared to 32.4% and 37.2% for the quarter and nine months ended September 30, 2007. This reflects the impact of estimated lower 2008 taxable income related to the Maryland settlement agreement, which increased the relative impact of unfavorable permanent tax adjustments on BGE's effective tax rate. These unfavorable permanent tax adjustments include the nondeductible portion of merger and strategic alternatives costs and the true-up of the 2007 tax provision to the 2007 tax return as filed. We discuss the merger and strategic alternatives costs in more detail on page 12 of the Notes to Consolidated Financial Statements.

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

Unrecognized Tax Benefits

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

At September 30, 2008
	(In millions)
Total unrecognized tax benefits, January 1, 2008	$	114.5
Increases in tax positions related to the current year		13.6
Reductions in tax positions related to prior years		(11.8	)
Reductions in tax positions related to audit settlements		(21.5	)
Total unrecognized tax benefits, September 30, 20081	$	94.8

1 BGE's portion of our total unrecognized tax benefits at September 30, 2008 was $4.7 million.

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

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

        Total unrecognized tax benefits as of September 30, 2008 of $94.8 million include outstanding state refund claims of approximately $49 million for which no tax benefit was recorded on our Consolidated Balance Sheets because refunds were not received and the claims do not meet the "more-likely-than-not" threshold.

        If the total amount of unrecognized tax benefits of $94.8 million were ultimately realized, our income tax expense would decrease by approximately $65 million. However, the $65 million includes state tax refund claims of approximately $49 million discussed above that have been disallowed by tax authorities and we believe that there

24

is a remote likelihood of ultimately realizing any benefit from these refund claim amounts. These refund claims and other unrecognized state tax benefits of $2.7 million currently being reviewed by state tax authorities may be resolved by September 30, 2009. For this reason, we believe it is reasonably possible that reductions to our total unrecognized tax benefits in the range of $40 to $50 million may occur by September 30, 2009, but would not materially impact income tax expense.

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

	Quarter Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(In millions)
Interest and penalties recorded as tax expense	$	0.2	$	2.2	$	1.9	$	4.6

        Accrued interest and penalties recognized in our Consolidated Balance Sheets were $12.7 million at September 30, 2008 and $16.8 million at December 31, 2007.

Taxes Other Than Income Taxes

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

	Quarter Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(In millions)
Taxes other than income taxes included in revenues—BGE	$	19.1	$	19.4	$	54.3	$	57.9

Commitments, Guarantees, and Contingencies

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

•

purchase of electric generating capacity and energy,

•

procurement and delivery of fuels,

•

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

•

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

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

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

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

        Our regulated gas business enters into various long-term contracts for the procurement, transportation, and storage of gas. Our regulated gas business has gas procurement, transportation and storage contracts that expire between 2008 and 2027. As discussed in Note 1 of our 2007 Annual Report on Form 10-K, our regulated gas business charges its customers for natural gas, and other associated costs, using gas adjustment clauses set by the Maryland PSC.

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

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

        At September 30, 2008, the total amount of commitments was $6,141.8 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

25

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

Guarantees

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

At September 30, 2008	Stated Limit
	(In millions)
Constellation Energy guarantees	$	17,539.1
Merchant energy business guarantees		80.6
BGE guarantees		250.0
Other non-regulated guarantees		1.2
Total guarantees	$	17,870.9

        At September 30, 2008, Constellation Energy had a total of $17,870.9 million in guarantees outstanding related to loans, credit facilities, and contractual performance of certain of its subsidiaries as described below.

•

Constellation Energy guaranteed a face amount of $17,539.1 million.

•

Constellation Energy guaranteed a face amount of $16,567.2 million on behalf of our merchant energy subsidiaries to allow those subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Our estimated net exposure for obligations under commercial transactions covered by these guarantees was approximately $3.8 billion at September 30, 2008, which represents the total amount the parent company could be required to fund based on September 30, 2008 market prices. For those guarantees related to our derivative liabilities, the fair value of the obligation is recorded in our Consolidated Balance Sheets.

•

Constellation Energy guaranteed $792.7 million primarily on behalf of our nuclear generating facilities for nuclear insurance and credit support to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants.

•

Constellation Energy guaranteed $22.7 million to our other merchant energy subsidiaries, primarily for non-nuclear generating facilities.

•

Constellation Energy guaranteed $156.5 million to its other nonregulated businesses of which $25.0 million was recorded in our Consolidated Balance Sheets at September 30, 2008. Constellation Energy guarantees two-thirds of certain debt of Safe Harbor Water Power Corporation, an unconsolidated investment. At September 30, 2008, Safe Harbor Water Power Corporation had outstanding debt of $65.0 million. The maximum amount of Constellation Energy's guarantee is $43.3 million.

•

Our merchant energy business guaranteed $80.6 million for loans, performance guarantees and other related payment obligations primarily related to certain power projects in which we have an investment.

•

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

•

Our other nonregulated business guaranteed $1.2 million for performance bonds.

Contingencies

Environmental Matters

Solid and Hazardous Waste

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

68th Street Dump

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

26

closer to completion. However, those costs could have a material effect on our financial results.

Spring Gardens

In December 1996, BGE signed a consent order with the Maryland Department of the Environment that requires it to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. The Spring Gardens site was once used to manufacture gas from coal and oil. Based on remedial action plans and cost modeling performed in late 2006, BGE estimates its probable clean-up costs will total $43 million. BGE has recorded these costs as a liability in its Consolidated Balance Sheets and has deferred these costs, net of accumulated amortization and amounts it recovered from insurance companies, as a regulatory asset. Based on the results of studies at this site, it is reasonably possible that additional costs could exceed the amount BGE has recognized by approximately $3 million. Through September 30, 2008, BGE has spent approximately $41 million for remediation at this site.

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

Air Quality

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

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

Water Quality

In October 2007, a subsidiary of Constellation Energy entered into a consent decree with the Maryland Department of the Environment relating to groundwater contamination at a third party facility that was licensed to accept fly ash, a byproduct generated by our coal-fired plants. The consent decree requires the payment of a $1.0 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. We recorded a liability in our Consolidated Balance Sheets of approximately $7.9 million, which includes the $1 million penalty and our estimate of probable costs to remediate contamination, replace drinking water supplies, monitor groundwater conditions, and otherwise comply with the consent decree. We have paid approximately $2.3 million of these costs as of September 30, 2008, resulting in a remaining liability at September 30, 2008 of $5.6 million. We estimate that it is reasonably possible that we could incur additional costs of up to approximately $10 million more than the liability that we accrued.

        In November 2007, a class action complaint was filed in Baltimore City Circuit Court alleging that the subsidiary's ash placement operations at the third party site damaged surrounding properties. The complaint seeks injunctive and remedial relief relating to the alleged contamination, unspecified compensatory damages for any personal injuries and property damages associated with the alleged contamination, and unspecified punitive damages. In September 2008, we entered into a non-binding agreement with representatives for the class action plaintiffs and, as a result, recorded a liability for the anticipated settlement. On October 31, 2008, we entered into a definitive settlement agreement which was filed with the Court and is subject to Court approval. The Court is expected to schedule a hearing for final approval of the settlement sometime in December 2008.

Litigation

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

Pending Merger with MidAmerican

Beginning September 18, 2008, six shareholders of Constellation Energy filed lawsuits in the Circuit Court for Baltimore City, Maryland challenging our pending merger with MidAmerican. Three similar suits have been filed by other shareholders of Constellation Energy in the United States District Court for the District of Maryland.

        The lawsuits claim that the merger consideration is inadequate and does not maximize value for shareholders, that the sales process leading up to the merger was unreasonably short and procedurally flawed, and that unreasonable deal protection devices were agreed to that ward off competing bids and coerce shareholders into accepting the merger. The federal lawsuits also assert that the conversion of the Preferred Stock issued to MidAmerican into debt is not permitted under Maryland

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law. The lawsuits seek declaratory judgments establishing the unenforceability of the merger based on the alleged breaches of duty, injunctive relief to enjoin the merger, rescission of the merger or rescissory damages, the imposition of a constructive trust in favor of shareholders of any benefits received by the individual members of the board of directors of Constellation Energy, and reasonable costs and expenses, including attorney's fees.

        Although Constellation Energy is unable at this time to determine the ultimate outcome of these lawsuits, injunctive relief or an adverse determination in these lawsuits could affect our ability to complete the pending merger.

Securities Class Action

On September 22, 2008, a federal securities class action lawsuit was filed in the United States District Court for the Southern District of New York on behalf of a proposed class of persons who acquired publicly traded securities, including the Series A Junior Subordinated Debentures, of Constellation Energy between January 30, 2008 and September 16, 2008, and who acquired Series A Junior Subordinated Debentures in an offering completed in June 2008. On October 27, 2008, another federal securities class action lawsuit was filed in the United States District Court for the District of Maryland, on behalf of a proposed class of persons who acquired common stock of Constellation Energy between January 30, 2008 and September 16, 2008.

        The New York securities class action alleges that Constellation Energy, a number of its present or former officers or directors, and the underwriters violated the securities laws by issuing a false and misleading registration statement and prospectus in connection with Constellation Energy's June 27, 2008 offering of Series A Junior Subordinated Debentures. The New York and Maryland securities class actions also allege that Constellation Energy issued false or misleading statements or was aware of material undisclosed information which contradicted public statements included in connection with its announcements of financial results for 2007, the fourth quarter of 2007, the first quarter of 2008 and the second quarter of 2008 and the filing of its first quarter 2008 Form 10-Q. The securities class actions seek, among other things, certification of the case as a class action, compensatory damages, reasonable costs and expenses, including counsel fees, and rescission damages.

        A lead plaintiff has not yet been appointed in either the New York or Maryland securities class action pursuant to the provisions of the Private Securities Litigation Reform Act and Constellation Energy and other defendants have accordingly not been required to respond to the complaint or take other action to defend the litigation. We are unable at this time to determine the ultimate outcome of the securities class action or its possible effect on our, or BGE's financial results.

ERISA Actions

In October and November 2008, four class action lawsuits were filed in the United States District Court for the District of Maryland and one class action was filed in the United States District Court for the Southern District of New York against Constellation Energy; Mayo A. Shattuck III, Constellation Energy's Chairman of the Board, President and Chief Executive Officer; and others in their roles as fiduciaries of the Constellation Energy Employee Savings Plan. The lawsuits allege that the defendants, in violation of various sections of ERISA, breached their fiduciary duties to prudently and loyally manage Constellation Energy Savings Plan's assets by designating Constellation Energy common stock as an investment, by failing to properly provide accurate information about the investment, by failing to properly monitor the investment and by failing to properly monitor other fiduciaries. The lawsuits seek to compel the defendants to reimburse the plaintiffs and the Constellation Energy Savings Plan for all losses resulting from the defendants' breaches of fiduciary duty, to impose a constructive trust on any unjust enrichment, to award actual damages with pre- and post-judgment interest, to award appropriate equitable relief including injunction and restitution and to award costs and expenses, including attorneys' fees. We are unable at this time to determine the ultimate outcome of these ERISA actions or their possible effect on our, or BGE's, financial results.

Mercury

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

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

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Asbestos

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

        Approximately 515 individuals who were never employees of BGE or Constellation Energy have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third-party claims brought by other defendants may also be filed against BGE and Constellation Energy in these actions. To date, most asbestos claims against us have been dismissed or resolved without any payment and a small minority have been resolved for amounts that were not material to our financial results. The remaining claims are currently pending in state courts in Maryland and Pennsylvania.

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

•

the identity of the facilities at which the plaintiffs allegedly worked as contractors,

•

the names of the plaintiffs' employers,

•

the dates on which and the places where the exposure allegedly occurred, and

•

the facts and circumstances relating to the alleged exposure.

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

Insurance

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

SFAS No. 133 Hedging Activities

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

Commodity Prices

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

•

fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on our electric generation operations,

•

fixing the price of a portion of anticipated fuel purchases for the operation of our power plants,

•

fixing the price for a portion of anticipated energy purchases to supply our load-serving customers,

•

fixing the price for a portion of anticipated sales of natural gas to customers, and

•

fixing the price for a portion of anticipated sales or purchases of freight and coal.

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

        Our merchant energy business designated certain fixed-price forward contracts as cash-flow hedges of forecasted sales of energy and forecasted purchases of fuel and energy for the years 2008 through 2016 under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Our merchant energy business had net unrealized pre-tax losses on these cash-flow hedges recorded in "Accumulated other comprehensive loss" of $1,946.7 million at September 30, 2008 and net unrealized pre-tax losses of $1,498.7 million at December 31, 2007.

        We expect to reclassify $945.0 million of net pre-tax losses on cash-flow hedges from "Accumulated other comprehensive loss" into earnings during the next twelve months based on market prices at September 30, 2008. However, the actual amount reclassified into earnings could vary from the amounts recorded at September 30, 2008, due to future changes in market prices. Additionally, for cash-flow hedges settled by physical delivery of the underlying commodity, "Reclassification of net gains or losses on hedging instruments from OCI to net income" represents the fair value of those derivatives, which is realized through gross settlement at the contract price.

        During the nine months ended September 30, 2008, we de-designated contracts previously designated as cash-flow hedges for which the forecasted transactions originally hedged are probable of not occurring and as a result we recognized a pre-tax gain of $17.7 million. During the nine months ended September 30, 2007, we de-designated contracts previously designated as cash-flow hedges for which the forecasted transactions originally hedged are probable of not occurring and as a result we recognized a pre-tax loss of $21.6 million.

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

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component of "Nonregulated revenues" in our Consolidated Statements of Income (Loss).

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

	Quarter Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In millions)
Cash-flow hedges	$	(13.2	)	$	32.5		$	(103.0	)	$	2.2
Fair value hedges		(6.2	)		(1.6	)		6.7			(0.5	)
Total	$	(19.4	)	$	30.9		$	(96.3	)	$	1.7

        The ineffectiveness amounts in the table above exclude:

•

a $31.8 million pre-tax loss related to the change in fair value of derivatives that did not qualify for cash-flow hedge accounting under SFAS No. 133 for some period within the nine months ended September 30, 2008, and

•

a $9.1 million pre-tax gain and $7.3 million pre-tax loss for the quarter and nine months ended September 30, 2007, respectively, related to the change in value for the portion of our fair value hedges excluded from our hedge effectiveness assessment.

Interest Rates

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

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

        "Accumulated other comprehensive loss" includes net unrealized pre-tax gains on interest rate cash-flow hedges terminated upon debt issuance totaling $12.0 million at September 30, 2008 and $11.9 million at December 31, 2007. We expect to reclassify $0.1 million of pre-tax net gains on these cash-flow hedges from "Accumulated other comprehensive loss" into "Interest expense" during the next twelve months. We had no hedge ineffectiveness on these swaps.

        In order to optimize the mix of fixed and floating-rate debt, we entered into interest rate swaps qualifying as fair value hedges relating to $450.0 million of our fixed-rate debt maturing in 2012 and 2015, and converted this notional amount of debt to floating-rate. The change in fair value of these hedges resulted in an unrealized gain of $23.6 million at September 30, 2008 and was recorded as an increase in our "Derivative assets" and "Long-term debt." The change in fair value of these hedges resulted in an unrealized gain of $11.8 million at December 31, 2007 and was recorded as an increase in our "Derivative assets" and "Long-term debt." We had no hedge ineffectiveness on these interest rate swaps.

Accounting Standards Issued

SFAS No. 161

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

Accounting Standards Adopted

FSP FIN 39-1

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

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value cash collateral that has been offset against our net derivative positions as part of our adoption of SFAS No. 157, Fair Value Measurements, below.

FSP SFAS No. 157-3

In October 2008, the FASB issued FSP SFAS No. 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active. FSP SFAS No. 157-3 does not change the guidance contained in SFAS No. 157, Fair Value Measurements; rather, it clarifies the application of SFAS No. 157 in a market that is not active. This FSP is effective for the periods ended September 30, 2008, and the adoption of this FSP did not have an effect on our financial results.

SFAS No. 157

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

        Consistent with the exit price concept, upon adoption we reduced our derivative liabilities to reflect our own credit risk. As a result, during the first quarter of 2008 we recorded a pre-tax reduction in "Accumulated other comprehensive loss" totaling $10 million for the portion related to cash-flow hedges and a pre-tax gain in earnings totaling $3 million for the remainder of our derivative liabilities. All other impacts of adoption were immaterial.

        We present all derivatives recorded at fair value net with the associated fair value cash collateral. This presentation of the net position reflects our credit exposure for our on-balance sheet positions but excludes the impact of any off-balance sheet positions and collateral. Examples of off-balance sheet positions and collateral include in-the-money accrual contracts for which the right of offset exists in the event of default and letters of credit. We discuss our letters of credit in more detail beginning on page 20.

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

			As of September 30, 2008
			Assets			Liabilities
			(In millions)
Cash equivalents			$	393.4		$	—
Debt and equity securities				1,237.4			—
Derivative instruments:
	Classified as derivative assets and liabilities:
		Current		1,604.7			(1,115.8	)
		Noncurrent		1,006.0			(1,171.1	)
		Total classified as derivative assets and liabilities		2,610.7			(2,286.9	)
	Classified as accounts receivable *			(971.4	)		—
	Total derivative instruments			1,639.3			(2,286.9	)
Total recurring fair value measurements			$	3,270.1		$	(2,286.9	)

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

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

        The table on the next page disaggregates our net derivative assets and liabilities on a gross contract-by-contract basis as required by SFAS No. 157. A primary focus of SFAS No. 157 is the fair value hierarchy that provides information about how fair value measurements are determined. SFAS No. 157 requires each individual asset or liability that is remeasured at fair value on a recurring basis to be presented in this table and classified, in its entirety, within the appropriate level in the fair value hierarchy. Therefore, the objective of this table is to provide information about how each individual derivative contract is valued within the fair value hierarchy, regardless of whether a particular contract is eligible for netting against other contracts or whether it has been collateralized. Because contracts with the same counterparty could fall into multiple levels within the fair value hierarchy, it is necessary to make this gross presentation in order to classify entire contracts into the appropriate fair value hierarchy level as required by SFAS No. 157. However, these gross balances are not indicative of either our actual credit exposure or net economic exposure since they do not reflect legally enforceable master netting

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agreements or cash or other forms of collateral, nor do they reflect the extent to which offsetting derivative and nonderivative positions or the capacity of physical assets reduce our economic exposure to risk. These gross balances are intended solely to provide information on sources of inputs to fair value and proportions of fair value involving objective versus subjective valuations.

        The table below sets forth by level within the fair value hierarchy the company's assets and liabilities that were measured at fair value on a recurring basis as of September 30, 2008. The gross derivative assets and liabilities presented in this table decreased significantly during the quarter ended September 30, 2008. This decrease is primarily due to a decreasing commodity price environment during the third quarter of 2008.

At September 30, 2008		Level 1			Level 2			Level 3			Netting and Cash Collateral*			Total Net Fair Value
		(In millions)
Cash equivalents		$	393.4		$	—		$	—		$	—		$	393.4
Debt and equity securities			375.9			861.5			—			—			1,237.4
Derivative assets			1,175.1			31,373.9			3,714.8			(34,624.5	)		1,639.3
Derivative liabilities			(1,276.3	)		(32,660.1	)		(3,000.2	)		34,649.7			(2,286.9	)
	Net derivative position		(101.2	)		(1,286.2	)		714.6			25.2			(647.6	)
Total		$	668.1		$	(424.7	)	$	714.6		$	25.2		$	983.2

* We present our derivative assets and liabilities in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master netting agreement exists between us and the counterparty to a derivative contract. At September 30, 2008, we included $126.3 million of cash collateral held and $101.1 million of cash collateral posted (excluding margin posted on exchange traded derivatives) in netting amounts in the above table. See discussion of FSP FIN 39-1 beginning on page 30 for more details on our net presentation.

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

•

Level 1—Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities.

•

Level 2—Pricing inputs other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date.

•

Level 3—Significant inputs that are generally not observable from market activity.

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

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

        Cash equivalents are comprised of exchange traded money market funds. These instruments are valued based upon unadjusted quoted prices in active markets and are classified within Level 1.

        Debt and equity securities include trust assets securing certain executive benefits, other marketable securities, and our nuclear decommissioning trust funds. Trust assets securing certain executive benefits consist of mutual funds, which are actively traded and are valued based upon unadjusted quoted prices, and are classified within Level 1. Our other marketable securities consist of publicly traded individual securities, which are valued based on unadjusted quoted prices in active markets, and are classified within Level 1. Nuclear decommissioning trust funds consist of a number of different types of securities, including the following:

•

publicly traded individual securities and United States Treasury securities are classified as Level 1 because they are valued based on unadjusted quoted prices in active markets,

•

fixed income securities other than United States Treasury securities are classified as Level 2 because these instruments are traded in markets that are less active than the markets for equity securities and United States Treasury securities, and

•

commingled funds are classified as Level 2 because they are valued based on the fund share price, which is observable on a less frequent basis.

        Derivative instruments include exchange-traded and bilateral contracts. Exchange-traded contracts include futures and certain options. Bilateral derivative instruments

32

include swaps, forwards, certain options and complex structured transactions. We utilize models to measure the fair value of bilateral derivative contracts. Generally, we use similar models to value similar instruments. Valuation models utilize various inputs, which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs, which are inputs derived principally from or corroborated by observable market data by correlation or other means. However, the primary input to our valuation models is the forward commodity price. We have classified derivative contracts within the fair value hierarchy as follows:

•

Exchange-traded derivative contracts valued based on unadjusted quoted prices in active markets are classified within Level 1.

•

Exchange-traded derivative contracts valued using pricing inputs based upon market quotes or market transactions are classified within Level 2. These contracts generally trade in less active markets due to the length of the contracts (i.e., for certain contracts the exchange sets the closing price, which may not be reflective of an actual trade).

•

Bilateral derivative contracts where observable inputs are available for substantially the full term and value of the asset or liability are classified in Level 2.

•

Bilateral derivative contracts with a lower availability of pricing information are classified in Level 3. In addition, complex or structured transactions, such as certain options, may require us to use internally-developed model inputs, which might not be observable in or corroborated by the market, to determine fair value. When such inputs have more than an insignificant impact on the measurement of fair value, we also classify the instrument in Level 3.

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

•

commodity prices,

•

price volatility,

•

volumes,

•

location,

•

interest rates,

•

credit quality of counterparties and Constellation Energy, and

•

credit enhancements.

        As previously mentioned, we incorporate the effect of exposure to a particular counterparty's credit (or counterparties exposure to us) in calculating the fair value of our derivative assets and liabilities. We adjust the value of our derivative assets to reflect the credit-worthiness of each counterparty based upon either published credit ratings or equivalent internal credit ratings and associated default probability percentages. We compute this adjustment by applying a default probability percentage to our outstanding credit exposure, net of collateral for each counterparty. The level of this adjustment increases/decreases as our credit exposure to counterparties increases/decreases, the maturity terms of our transactions increase/decrease, or the credit ratings of our counterparties deteriorate/improve. We also assess whether the counterparties published credit rating is reflective of current market conditions based on review of available observable data including bond prices and yields and credit default swaps.

        We regularly evaluate and validate the inputs we use to estimate fair value by a number of methods, consisting of various market price verification procedures, including the use of pricing services and multiple broker quotes to support the market price of the various commodities in which we transact, as well as review and verification of models and changes to those models. These activities are undertaken by individuals that are independent of those responsible for estimating fair value.

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

33

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

		Quarter ended September 30, 2008			Nine months ended September 30, 2008
		(In millions)
Balance at beginning of period		$	211.4		$	(147.1	)
Realized and unrealized gains (losses):
	Recorded in income		37.4			203.3
	Recorded in other comprehensive income		(24.3	)		226.2
Purchases, sales, issuances, and settlements			(39.5	)		(3.2	)
Transfers into and out of level 3			529.6			435.4
Balance as of September 30, 2008		$	714.6		$	714.6
Change in unrealized gains relating to derivatives still held as of September 30, 2008		$	338.8		$	478.5

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

        Realized and unrealized gains (losses) include the realization of derivative contracts through maturity. This includes the fair value, as of the beginning of each quarterly reporting period, of contracts that matured during each quarterly reporting period. Purchases, sales, issuances, and settlements represent cash paid or received for option premiums, and the acquisition or termination of derivative contracts prior to maturity, including the $46.2 million embedded derivative liability contained in the Preferred Stock issued to MidAmerican. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the inputs to the model became unobservable. Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable based on the criteria discussed on the previous page for classification in either Level 1 or Level 2.

Related Party Transactions

Constellation Energy

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

BGE—Income Statement

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

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

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

	Quarter Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(In millions)
Purchased energy	$	175.6	$	355.1	$	632.9	$	912.1

        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,
	2008		2007		2008		2007
	(In millions)
Charges to BGE	$	44.5	$	41.8	$	114.6	$	111.6

34

BGE—Balance Sheet

BGE participates in a cash pool under a Master Demand Note agreement with Constellation Energy. Under this arrangement, participating subsidiaries may invest in or borrow from the pool at market interest rates. Constellation Energy administers the pool and invests excess cash in short-term investments or issues commercial paper to manage consolidated cash requirements. Under this arrangement, BGE had invested $63.1 million at September 30, 2008 and $78.4 million at December 31, 2007.

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

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

35

Item 2. Management's Discussion

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

Introduction and Overview

Constellation Energy Group, Inc. (Constellation Energy) is an energy company that conducts its business through various subsidiaries including a merchant energy business and Baltimore Gas and Electric Company (BGE). We describe our operating segments in the Notes to Consolidated Financial Statements beginning on page 18.

        This Quarterly Report on Form 10-Q is a combined report of Constellation Energy and BGE. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "regulated business(es)" are to BGE. We discuss our business in more detail in Item 1—Business section of our 2007 Annual Report on Form 10-K and we discuss the risks affecting our business in Item 1A. Risk Factors section beginning on page 68.

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

•

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

•

Strategy section,

•

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

•

Critical Accounting Policies section.

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

        Effective January 1, 2008, we adopted SFAS No. 157, Fair Value Measurements, as discussed in the Notes to Consolidated Financial Statements beginning on page 31. We discuss our accounting policy for determining fair value in more detail in the Notes to Consolidated Financial Statements as well as in our Critical Accounting Policies section and Note 1 in our 2007 Annual Report on Form 10-K.

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

•

factors which affect our businesses,

•

our earnings and costs in the periods presented,

•

changes in earnings and costs between periods,

•

sources of earnings,

•

impact of these factors on our overall financial condition,

•

expected future expenditures for capital projects, and

•

expected sources of cash for further capital expenditures.

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

        We have organized our discussion and analysis as follows:

•

We describe changes to our strategy and our business environment during the year.

•

We highlight significant events that occurred in 2008 that are important to understanding our results of operations and financial condition.

•

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

•

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

•

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

Strategy

We discuss our business strategy in detail in the Strategy section of our 2007 Annual Report on Form 10-K. In that discussion, we indicate that we are constantly reevaluating our strategies. As a result of the unprecedented events of 2008 as discussed below, in addition to focusing on our basic business plan, we have made substantial changes in our strategy, including focusing on the following immediate goals:

•

reducing the capital requirements, economic risk and collateral needs of our merchant energy businesses, which we discuss in further detail beginning on page 62,

36

•

executing strategic initiatives for our Global Commodities business, which include the sale of our upstream gas properties, our international business, which includes our coal sourcing, freight, uranium, power, natural gas and emissions marketing activities outside North America, and our gas trading activities, and

•

obtaining necessary approvals and executing other activities to close our merger with MidAmerican Energy Holdings Company (MidAmerican).

        The execution of our strategy in the future will be affected by our ability to achieve these goals as well as by continued instability in financial and commodities markets. Execution of our goals could have a substantial effect on the nature and mix of our business activities. In turn, this could affect our financial position, results of operations, and cash flows in material amounts, and these amounts could vary substantially from historical results.

Business Environment

Various factors affect our financial results. We discuss these various factors in the Forward Looking Statements section on page 74 and in Item 1A. Risk Factors section beginning on page 68. We discuss our market risks in the Market Risk section beginning on page 64.

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

Federal Regulation

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

Environmental Matters

Air Quality

National Ambient Air Quality Standards (NAAQS)

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

        In July 2008, the United States Court of Appeals for the District of Columbia Circuit issued a ruling that effectively repealed the Clean Air Interstate Rule (CAIR). We do not believe that the decision will result in a material change to our emissions reduction plan in Maryland as the emissions reduction requirements of Maryland's Healthy Air Act and Clean Power Rule are more stringent and apply sooner than those under CAIR. On September 24, 2008, the EPA petitioned the District of Columbia Circuit for rehearing. We cannot predict what additional judicial, legislative or regulatory actions will be taken in response to the court's decision or the EPA's petition for rehearing or whether such actions may affect our financial results. We discuss the impact that this ruling had on our third quarter of 2008 results in the Merchant Energy Business section on page 45. We discuss this ruling in more detail in the Notes to Consolidated Financial Statements beginning on page 17.

Capital Expenditures

As discussed in our 2007 Annual Report on Form 10-K, we expect to incur additional environmental capital expenditures to comply with air quality laws and regulations. Based on updated information from vendors, we expect our estimated environmental capital requirements for these air quality projects to be approximately $550 million in 2008, $305 million in 2009, $40 million in 2010 and $35 million from 2011-2012.

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

Accounting Standards Issued and Adopted

We discuss recently issued and adopted accounting standards in the Accounting Standards Issued and Accounting Standards Adopted sections of the Notes to Consolidated Financial Statements beginning on page 30.

Events of 2008

Pending Merger with MidAmerican

On September 19, 2008, Constellation Energy entered into an Agreement and Plan of Merger with MidAmerican. We discuss the details of this pending merger in the Notes to Consolidated Financial Statements beginning on page 11.

37

Current Market Developments

Volatility in the financial markets throughout 2008 intensified in the third quarter, leading to dramatic declines in equity prices and substantially reducing liquidity in the credit markets. Most equity indices declined significantly, the cost of credit default swaps and bond spreads increased substantially, and credit markets effectively ceased to be accessible for all but the most highly rated borrowers.

        Precipitated by these conditions, major financial institutions experienced significant financial difficulty and widespread fears developed about the viability of any business that required access to credit markets to support liquidity needs or that required substantial access to the capital markets to function. During the week of September 15, 2008, Constellation Energy faced rapidly growing doubts among investors and business partners about its ability to navigate through this market crisis. Concerns focused on our liquidity, and the trading price of our common stock fell to a 52-week low of $13.00 during the day on September 16, 2008. Despite having announced a number of actions to address our liquidity situation, we needed to raise immediate equity capital and take other steps to enhance our overall liquidity, and as a result on September 19, 2008, we entered into a definitive merger agreement with MidAmerican. We discuss our pending merger with MidAmerican in more detail in the Notes to Consolidated Financial Statements beginning on page 11.

        This market environment contributed to the following:

•

Our senior unsecured debt was downgraded one level by all three major credit rating agencies and we remain under review for possible downgrade by Moody's Investors Service. We discuss our security ratings and downgrade collateral in more detail beginning on page 59.

•

We were required to post additional collateral with counterparties. We discuss our collateral requirements in more detail beginning on page 58.

•

We initiated strategic alternatives for our upstream gas properties, our international business, and our gas trading operations as well as other strategies to improve liquidity and reduce invested capital. We discuss our strategy in more detail beginning on page 36.

•

We anticipate closing in November 2008 on a new credit facility of approximately $1.2 billion. We discuss this in more detail in the Notes to Consolidated Financial Statements on page 21.

•

We took various other steps to reduce our exposure to the credit risk of other parties and to improve our own liquidity. We discuss our liquidity beginning on page 60.

•

In connection with the proposed merger with MidAmerican, we received a capital infusion of $1 billion from MidAmerican on September 22, 2008. We discuss the $1 billion in proceeds from MidAmerican in the Notes to Consolidated Financial Statements beginning on page 21.

•

We recorded significant impairment charges in the third quarter of 2008. We discuss these impairment charges in more detail in the Notes to Consolidated Financial Statements beginning on page 12.

•

We incurred losses on our pension plan assets. We discuss our pension plan assets in more detail on page 57.

Commodity Prices

During the six months ended June 30, 2008 and nine months ended September 30, 2008, the energy markets were affected by large fluctuations in commodity prices as indicated in the following table:

Increases (decreases)	Six months ended June 30, 2008			Nine months ended September 30, 2008
Power		33	%		(8	)%
Natural gas		44	%		(5	)%
Coal		153	%		58	%
Crude oil		55	%		1	%

        During the third quarter of 2008 and continuing into the fourth quarter of 2008, prices for most commodities, including energy, fell sharply after peaking early in July. The commodity price environment contributed to the following impacts on our results:

•

As a result of volatile commodity prices, we experienced significant mark-to-market gains during the six months ended June 30, 2008 and significant mark-to-market losses during the quarter ended September 30, 2008. We discuss our mark-to-market results in our Mark-to-Market section beginning on page 46.

•

Our total derivative assets increased $819.9 million and total derivative liabilities increased $33.7 million since December 31, 2007. We discuss our derivative assets and liabilities in more detail beginning on page 48.

•

During the third quarter of 2008, we were required to return portions of counterparty collateral we held and to post additional collateral with counterparties. We discuss our collateral requirements in more detail beginning on page 58.

•

We experienced an increase in our exposure to lower credit quality wholesale counterparties during the six months ended June 30, 2008 and a decrease in our exposure to lower credit quality wholesale counterparties during the quarter ended September 30, 2008 primarily due to the volatility of coal prices. We discuss our wholesale credit risk

38

exposure in more detail in the Wholesale Credit Risk section beginning on page 65.

•

One of our domestic coal suppliers was unable to meet production targets and filed for bankruptcy. As a result, in the quarter ended March 31, 2008, we incurred a credit loss related to this supplier. We discuss the impact of this event on our results in more detail on page 46.

•

We executed several contract settlements and amended certain other contracts, primarily in the quarter ended March 31, 2008, to reduce our exposure to supplier nonperformance risk and/or credit risk. We discuss these transactions in more detail on page 46.

Merger and Strategic Alternatives Costs

We incurred costs during the third quarter of 2008 related to our pending merger with MidAmerican and the pursuit of other strategic alternatives to that merger. We discuss these costs in more detail in the Notes to Consolidated Financial Statements on page 12.

Workforce Reduction Costs

During the third quarter of 2008, our merchant energy business approved a restructuring of its Customer Supply operations and recognized a $2.2 million pre-tax charge. We discuss our workforce reduction costs in more detail in the Notes to Consolidated Financial Statements on page 16.

Emission Allowances

During the third quarter of 2008, as a result of a July 11, 2008 decision by the United States Court of Appeals for the D. C. Circuit that vacated the Clean Air Interstate Rule and the subsequent decline in market price for our emission allowance inventory, we recorded a write-down of our emissions inventory and recognized partially offsetting gains on certain forward sales contracts. We discuss this net charge in the Notes to Consolidated Financial Statements beginning on page 17.

Acquisitions

Hillabee Energy Center

On February 14, 2008, we acquired a partially completed gas-fired power generating facility in Alabama. We discuss this acquisition in more detail in the Notes to Consolidated Financial Statements on page 16.

West Valley Power Plant

On June 1, 2008, we acquired a gas-fired peaking plant in Utah. We discuss this acquisition in more detail in the Notes to Consolidated Financial Statements on page 16.

Nufcor International Limited

On June 26, 2008, we acquired a uranium marketing services company in the United Kingdom. We discuss this acquisition in more detail in the Notes to Consolidated Financial Statements beginning on page 16.

Asset Sales

Working Interests in Gas Producing Property

On June 30, 2008, we sold a portion of our working interests in certain proved and unproved oil and gas properties. We discuss this asset sale in more detail in the Notes to Consolidated Financial Statements on page 17.

Dry Bulk Vessel

On July 10, 2008, a shipping joint venture in which our merchant energy business owns a 50% ownership interest sold one of six dry bulk vessels it owns for a gain to us of approximately $29 million. We discuss this sale in more detail in the Notes to Consolidated Financial Statements on page 17.

Financing Activities

In June 2008, we issued the following:

•

$250.0 million of Zero Coupon Senior Notes due June 2023, and

•

$450.0 million of Series A Junior Subordinated Debentures due June 2063.

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

        In connection with the merger with MidAmerican, Constellation Energy issued 10,000 shares of 8% Series A Convertible Preferred Stock (Preferred Stock) that are mandatorily redeemable on September 22, 2010 to MidAmerican for $1 billion. If the merger is terminated other than because of a breach by MidAmerican or is not completed by June 19, 2009 (which may be extended to September 19, 2009), the Preferred Stock automatically converts into $1 billion of 14% Senior Notes of Constellation Energy and requires a payment to MidAmerican of Constellation Energy common stock or cash if approvals to issue shares have not yet been received. We discuss the Preferred Stock in more detail in the Notes to Consolidated Financial Statements beginning on page 21.

        We discuss our financing activities in more detail in the Notes to Consolidated Financial Statements beginning on page 20.

Maryland Settlement Agreement

In March 2008, Constellation Energy, BGE and a Constellation Energy affiliate entered into a settlement agreement with the State of Maryland, the Maryland PSC and certain State of Maryland officials to resolve pending litigation and to settle other prior legal, regulatory and legislative issues. We discuss this settlement in more detail in the Notes to Consolidated Financial Statements on page 23.

39

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

In this section, we discuss our earnings and the factors affecting them. We begin with a general overview, then separately discuss earnings for our operating segments. Changes in other income, fixed charges, and income taxes are discussed, as necessary, in the aggregate for all segments in the Consolidated Nonoperating Income and Expenses section beginning on page 56.

Overview

Results

		Quarter Ended September 30,						Nine Months Ended September 30,
		2008			2007			2008			2007
		(In millions, after-tax)
Merchant energy		$	(246.0	)	$	226.5		$	105.9		$	450.3
Regulated electric			31.7			34.3			(38.8	)		85.9
Regulated gas			(12.2	)		(9.8	)		24.1			18.2
Other nonregulated			0.8			(0.3	)		0.3			9.9
(Loss) Income from Continuing Operations			(225.7	)		250.7			91.5			564.3
	Income (loss) from discontinued operations		—			0.7			—			(0.9	)
Net (Loss) Income		$	(225.7	)	$	251.4		$	91.5		$	563.4
Other Items Included in Operations (after-tax)
	Impairments and other costs	$	(298.8	)	$	—		$	(298.8	)	$	(12.2	)
	Merger and strategic alternatives costs		(37.3	)		—			(37.3	)		—
	Accrual of Maryland settlement credit		—			—			(125.3	)		—
	Effective tax rate impact of Maryland settlement agreement		2.0			—			10.7			—
	Impairment of nuclear decommissioning trust assets		(15.3	)		—			(21.5	)		—
	Emission allowance write-down, net		(22.8	)		—			(36.2	)		—
	Non-qualifying hedges		12.0			1.9			(57.3	)		(6.0	)
	Workforce reduction costs		(1.6	)		—			(1.6	)		(1.5	)
Total Other Items		$	(361.8	)	$	1.9		$	(567.3	)	$	(19.7	)

Quarter and Nine Months Ended September 30, 2008

Our total net income for the quarter and nine months ended September 30, 2008 compared to the same periods of 2007 decreased primarily due to the following:

	Quarter Ended September 30,			Nine Months Ended September 30,
	2008 vs. 2007
	(In millions, after-tax)
Generation gross margin	$	78		$	105
Customer Supply gross margin		(28	)		(4	)
Global Commodities gross margin		(200	)		47
Sale of upstream gas assets		—			55
2007 sale of CEP LLC equity		(24	)		(31	)
Hedge ineffectiveness		(28	)		(43	)
Credit loss—coal supplier bankruptcy		—			(33	)
Merchant operating expenses, primarily labor and benefit costs		99			24
Merchant interest expense		(19	)		(35	)
Synthetic fuel facilities		15			(11	)
Other nonregulated businesses		—			(10	)
Total Other Items included in operations per Overview—Results table		(364	)		(548	)
Interest and investment income		(9	)		(27	)
All other changes		3			39
Total	$	(477	)	$	(472	)

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

40

Merchant Energy Business

Background

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

        Our merchant energy business focuses on delivery of physical, customer-oriented products to producers and consumers, manages the risk and optimizes the value of our owned generation assets, and uses our portfolio management and trading capabilities both to manage risk and to deploy risk capital to generate additional returns. Currently, we are assessing the ongoing capital requirements of the merchant energy business, including evaluating the proper size of our Customer Supply business, and with respect to our Global Commodities business we are considering various strategic alternatives. As previously discussed, we have made substantial changes in our strategy, including focusing on the following immediate goals:

•

reducing the capital requirements, economic risk and collateral needs of our Global Commodities and Customer Supply operations, and,

•

executing strategic alternatives for our Global Commodities business, which include the sale of our upstream gas properties, our international business, which includes our coal sourcing, freight, uranium, power, natural gas and emissions marketing activities outside North America, and our gas trading activities.

        The execution of our strategy in the future will be affected by our ability to achieve these goals as well as by continued instability in financial and commodities markets. Execution of our goals could have a substantial effect on the nature and mix of our business activities. In turn, this could affect our financial position, results of operations, and cash flows in material amounts, and these amounts could vary substantially from historical results. We discuss our strategy in more detail beginning on page 36.

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

•

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

•

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

•

We record changes in the fair value of contracts that are subject to mark-to-market accounting in revenues or fuel and purchased energy expenses in the period in which the change occurs.

        The accounting for derivatives requires us to use judgment to make estimates and assumptions in determining the fair value of certain contracts and in recording revenues from those contracts. We discuss the effects of mark-to-market accounting on our results in the Mark-to-Market section beginning on page 46.

        Our Global Commodities operation actively transacts in energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions. As part of these activities, we trade energy and energy-related commodities and deploy risk capital in the management of our portfolio in order to earn additional returns. These activities are managed through daily value at risk and stop loss limits and liquidity guidelines, and may have a material impact on our financial results. We discuss the impact of our portfolio management and trading activities and value at risk in more detail in the Mark-to-Market section beginning on page 46 and the Market Risk section beginning on page 64. As discussed above, we are currently assessing the ongoing capital requirements of the merchant energy business and are considering various alternative strategies. Additionally, we have focused our activities on reducing capital required, reducing long-term economic risk, and reducing short-term liquidity requirements. These actions may impact the future results of the merchant energy business.

41

Results

		Quarter Ended September 30,						Nine Months Ended September 30,
		2008			2007			2008			2007
		(In millions)
Revenues		$	4,492.6		$	5,275.9		$	12,719.7		$	14,113.7
Fuel and purchased energy expenses			(3,843.0	)		(4,319.2	)		(10,371.1	)		(11,808.0	)
Operating expenses			(322.0	)		(486.1	)		(1,298.0	)		(1,338.0	)
Impairments and other costs			(477.1	)		—			(477.1	)		(20.2	)
Workforce reduction costs			(2.2	)		—			(2.2	)		(2.3	)
Merger and strategic alternatives costs			(27.2	)		—			(27.2	)		—
Depreciation, depletion, and amortization			(68.6	)		(66.9	)		(207.8	)		(197.7	)
Accretion of asset retirement obligations			(17.2	)		(16.0	)		(50.8	)		(51.9	)
Taxes other than income taxes			(35.8	)		(29.1	)		(94.0	)		(85.0	)
Gains on sales of upstream gas assets			—			—			91.5			—
(Loss) Income from Operations		$	(300.5	)	$	358.6		$	283.0		$	610.6
(Loss) Income from Continuing Operations (after-tax)		$	(246.0	)	$	226.5		$	105.9		$	450.3
	Income (loss) from discontinued operations (after-tax)		—			0.7			—			(0.9	)
Net (Loss) Income		$	(246.0	)	$	227.2		$	105.9		$	449.4
Other Items Included in Operations (after-tax)
	Impairments and other costs	$	(298.8	)	$	—		$	(298.8	)	$	(12.2	)
	Merger and strategic alternatives costs		(25.8	)		—			(25.8	)		—
	Impairment of nuclear decommissioning trust assets		(15.3	)		—			(21.5	)		—
	Emission allowance write-down, net		(22.8	)		—			(36.2	)		—
	Non-qualifying hedges		12.0			1.9			(57.3	)		(6.0	)
	Workforce reduction costs		(1.6	)		—			(1.6	)		(1.5	)
Total Other Items		$	(352.3	)	$	1.9		$	(441.2	)	$	(19.7	)

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

Revenues and Fuel and Purchased Energy Expenses

Our merchant energy business manages the revenues we realize from the sale of energy and energy-related products to our customers and our costs of procuring fuel and energy. As previously discussed, our merchant energy business uses either accrual, cash-flow hedge, or mark-to-market accounting to record our revenues and expenses. Mark-to-market results reflect the net impact of amounts recorded in earnings to recognize the changes in fair value of derivative contracts subject to mark-to-market accounting during the reporting period. We discuss the effects of mark-to-market accounting on our results separately in the Mark-to-Market section beginning on page 46.

Revenues

Our merchant energy revenues decreased $783.3 million and $1,394.0 million during the quarter and nine months ended September 30, 2008, respectively, compared to the same periods in 2007 primarily due to the following:

	Quarter Ended September 30,			Nine Months Ended September 30,
	2008 vs. 2007
	(In millions)
Change in Global Commodities trading mark-to-market revenues due to unfavorable changes in power and gas prices	$	(219	)	$	(27	)
Change in contract prices primarily related to our coal businesses		(105	)		23
Realization of higher contract prices on wholesale and retail load at our Global Commodities and Customer Supply operations		217			401
All other (substantially all due to change in gas procurement activities)1		(676	)		(1,791	)
Total decrease in merchant energy revenues	$	(783	)	$	(1,394	)

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

42

Fuel and Purchased Energy Expenses

During the quarter and nine months ended September 30, 2008, merchant energy fuel and purchased energy expenses decreased $476.2 million and $1,436.9 million, respectively, compared to the same periods in 2007 primarily due to the following:

	Quarter Ended September 30,			Nine Months Ended September 30,
	2008 vs. 2007
	(In millions)
Change in Global Commodities mark-to-market expenses related to international coal purchase contracts	$	(211	)	$	(219	)
Change in contract prices primarily related to our coal businesses		(119	)		12
Realization of higher contract prices on wholesale and retail purchases at our Global Commodities and Customer Supply operations		280			510
Decrease in synfuels expenses due to expiration of tax credits in 2007		(32	)		(110	)
All other (substantially all due to change in gas procurement activities)1		(394	)		(1,630	)
Total decrease in merchant energy purchased fuel and energy expenses	$	(476	)	$	(1,437	)

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

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

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

•

Generation—our operation that owns, operates, and maintains fossil, nuclear, and renewable generating facilities and holds interests in qualifying facilities, a fuel processing facility and power projects in the United States. We present the gross margin results of this operation based on a 100% hedged assumption for the portfolio in the current year, related to both output from the facilities and the fuel used to generate electricity. The assumption is based on executing hedges at current market prices with the Global Commodities operation at the end of each fiscal year in order to ensure that the Generation operation is fully hedged. Therefore, all commodity price risk is managed by and presented in the results of our Global Commodities operation as discussed beginning on page 45. Changes in gross margin of our Generation operation during the period are due to changes in the level of output from the generating assets, and changes in gross margin between years are a result of changes in prices and expected output.

43

•

Customer Supply—our load-serving operation that provides energy products and services to wholesale and retail electric and natural gas customers, including distribution utilities, cooperatives, aggregators, and commercial, industrial and governmental customers. We present the gross margin results of this operation based on the gross margin value of new customer supply arrangements at the time of execution assuming an estimated level of customer usage and the impact of any changes in the underlying usage of the customers based on actual energy deliveries. Changes in estimated customer usage result from attrition (customers changing suppliers) or variable load risk (changes in actual usage when compared to expected usage). All commodity price risk is presented in and managed by our Global Commodities operation as discussed beginning on the next page.

•

Global Commodities—our marketing, risk management, and trading operation that manages contractually owned physical assets, including generation facilities, natural gas properties, international coal and freight assets, provides risk management services, and trades energy and energy-related commodities. This operation provides the wholesale risk management function for our Generation and Customer Supply operations and includes our merchant energy business' actual hedged positions with third parties. Therefore, changes in gross margin for this operation result mostly from changes in commodity prices and positions across the various commodities and regions in which we transact.

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

		Quarter Ended September 30,											Nine Months Ended September 30,
		2008						2007					2008					2007
		(Dollar amounts in millions)
					% of Total					% of Total					% of Total					% of Total
Gross Margin:
	Generation	$	626			96	%	$	497		52	%	$	1,499		64	%	$	1,326		58	%
	Customer Supply		142			22			189		20			537		23			544		23
	Global Commodities		(119	)		(18	)		271		28			312		13			436		19
	Total	$	649			100	%	$	957		100	%	$	2,348		100	%	$	2,306		100	%

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

Generation

The $129 million increase in Generation gross margin during the quarter ended September 30, 2008 compared to the same period of 2007 is primarily due to the following:

•

approximately $125 million increase from higher energy prices for the output of our generating assets primarily in the PJM region based on prices established at the end of the prior year (see Global Commodities discussion beginning on the next page for impact of current year price changes), and

•

higher earnings of approximately $4 million from lower planned and unplanned outages at our nuclear and fossil plants.

        The $173 million increase in generation gross margin during the nine months ended September 30, 2008 compared to the same period of 2007 is primarily due to the following:

•

approximately $147 million increase from higher energy prices for the output of our generating assets primarily in the PJM region based on prices established at the end of the prior year (see Global Commodities discussion beginning on the next page for impact of current year price changes),

•

higher earnings of approximately $16 million from our investments in power projects, and

•

higher earnings of approximately $10 million from lower planned and unplanned outages at our nuclear plants.

44

Customer Supply

The $47 million decrease in Customer Supply gross margin during the quarter ended September 30, 2008 compared to the same period of 2007 is primarily due to the following:

•

approximately $38 million of lower mark-to-market results in our retail gas business. We discuss our mark-to-market results in more detail in the Mark-to-Market section beginning on page 46,

•

approximately $35 million of lower gross margin due to lower prices and decreased sales volumes at our retail power operation, and

•

approximately $14 million of lower gross margin related to lower realization of contracts executed in prior periods and lower new business originated and realized during the quarter at our wholesale power operation.

        These decreases were partially offset by the following:

•

approximately $36 million of lower costs from managing variable load risk associated with wholesale and retail power primarily due to less extreme summer weather during the quarter, and

•

approximately $10 million of higher gross margin at our retail gas operation primarily due to the acquisition of Cornerstone Energy in July 2007.

        The $7 million decrease in Customer Supply gross margin during the nine months ended September 30, 2008 compared to the same period of 2007 is primarily due to approximately $70 million of lower expected realization of contracts executed in prior periods and lower new business originated and realized during the nine months ended September 30, 2008.

        This decrease was partially offset by the following:

•

approximately $28 million of higher gross margin at our retail gas operation primarily due to the acquisition of Cornerstone Energy in July 2007,

•

approximately $23 million of lower costs from managing variable load risk associated with wholesale and retail power primarily due to less extreme weather during the nine months ended September 30, 2008, and

•

approximately $12 million of higher mark-to-market results in our retail gas business. We discuss our mark-to-market results in more detail in the Mark-to-Market section beginning on page 46.

Global Commodities

We present Global Commodities results in the following categories:

•

Portfolio Management and Trading—our centralized risk management service related to energy price risk associated with our generation fleet, wholesale and retail customer supply business, and our structured products portfolio. It also deploys risk capital in traded energy markets.

•

Structured Products—customized risk management products in the power, gas, coal and freight markets (e.g., generation tolls, gas transport and storage, and global coal and freight logistics).

•

Energy Investments—investments in energy assets that primarily include natural gas properties and a joint interest in an entity that owns dry bulk cargo vessels.

        As previously discussed in the Events of 2008 section beginning on page 38, the energy markets were affected by substantial changes in commodity prices during the nine months ended September 30, 2008. These market impacts are reflected in the $390 million decrease in gross margin from our Global Commodities activities during the quarter ended September 30, 2008 compared to the same period of 2007. This decrease is primarily a result of approximately $466 million of lower gross margin related to our portfolio management and trading operation due to the following factors:

•

approximately $254 million of lower gross margin related to portfolio management of positions arising from our Generation, Customer Supply, and structured products activities due to the impact of changes in prices of power, natural gas, and coal on those positions,

•

approximately $107 million of lower gross margin related to our portfolio of contracts subject to mark-to-market accounting. We discuss these transactions in more detail in the Mark-to-Market section beginning on page 46,

•

approximately $59 million related to a write-down of our emission allowance inventory to reflect current market price decreases. We discuss this in more detail in the Notes to Consolidated Financial Statements beginning on page 17, and

•

approximately $46 million related to losses recognized on hedges due to ineffectiveness and certain cash-flow hedges that no longer qualified for hedge accounting during the quarter.

        The decrease in gross margin is partially offset by higher gross margin of:

•

approximately $40 million from gains in our structured products portfolio as a result of the termination and sale of in-the-money energy purchase contracts, coal supply contracts, and freight contracts to eliminate or reduce operation and performance risk with certain counterparties, and

•

approximately $36 million in our energy investments operation primarily due to a $29 million gain on sale of a dry bulk vessel in our shipping joint venture. We discuss this sale in more detail in the Notes to Consolidated Financial Statements on page 17.

45

        The $124 million decrease in gross margin from our Global Commodities operation for the nine months ended September 30, 2008 compared to the same period in 2007 is primarily due to lower gross margin of approximately $405 million related to our portfolio management and trading operation, partially offset by approximately $204 million of higher gross margin in our structured products portfolio and approximately $77 million of higher gross margin in our energy investments portfolio. We discuss these changes below.

        The decrease in gross margin of $405 million as a result of portfolio management and trading is primarily related to the following:

•

approximately $342 million of lower gross margin related to portfolio management of positions arising from our Generation, Customer Supply, and structured products activities due to the impact of changes in prices of power, natural gas, and coal on those positions,

•

approximately $81 million related to the write-down of our emission allowance inventory. We discuss this in more detail in the Notes to Consolidated Financial Statements beginning on page 17,

•

approximately $71 million related to losses recognized on hedges due to ineffectiveness and certain cash-flow hedges that no longer qualified for hedge accounting during the quarter, and

•

approximately $55 million related to the bankruptcy of one of our domestic coal suppliers. During the first quarter of 2008, as a result of a default by the supplier, we terminated our derivative contracts with the supplier, reclassified the related asset to accounts receivable and fully reserved the amount. Prior to this default, we had recorded unrealized gains totaling $55 million that remain in "Accumulated other comprehensive loss" and will be reclassified to earnings as the forecasted transactions occur. The majority is being reclassified to earnings during 2008, and the remainder will be fully realized by 2010.

        These decreases were partially offset by the following:

•

approximately $97 million of higher gross margin related to our portfolio of contracts subject to mark-to-market accounting, including higher earnings of approximately $36 million related to increased origination gains primarily associated with amended nonderivative contracts for which mark-to-market accounting is now required. We discuss these transactions in more detail in the Mark-to-Market section on page 48, and

•

approximately $47 million of higher gross margin related to higher realization from contracts executed in prior periods.

        The increase in gross margin of $204 million for the structured products portfolio is primarily related to the following:

•

approximately $180 million of higher gross margin related to gains recognized as a result of termination and sale of in-the-money energy purchase contracts, coal supply contracts, and freight contracts to eliminate or reduce operational and performance risk with certain counterparties, and

•

approximately $24 million of higher gross margin related to higher realization from contracts executed in prior periods.

        The increase in gross margin of $77 million for energy investments is primarily related to the following:

•

approximately $38 million of earnings primarily due to the sale of a dry bulk vessel in our shipping joint venture. We discuss this in more detail in the Notes to Consolidation Financial Statements on page 17,

•

approximately $31 million due to higher realization from contracts executed in prior periods and higher new business originated and realized during the period, and

•

approximately $5 million due to the recognition of gains on certain cash flow hedges that no longer qualified for hedge accounting during the third quarter of 2008.

Mark-to-Market

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

        As a result of the nature of our operations and the use of mark-to-market accounting for certain activities, mark-to-market earnings will fluctuate. We cannot predict these fluctuations, but the impact on our earnings could be material. We discuss our market risk in more detail in the Market Risk section beginning on page 64. The primary factors that cause fluctuations in our mark-to-market results are:

•

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

•

the number and size of our open derivative positions, and

•

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

        As discussed earlier, we are currently assessing the ongoing capital requirements of the merchant energy business and are considering various alternative strategies.

46

Additionally, we have focused our activities on reducing capital requirements, reducing long-term economic risk, and reducing short-term liquidity requirements. These actions may impact the future results of the merchant energy business, particularly the size of and potential for changes in fair value of activities subject to mark-to-market accounting. In the fourth quarter of 2008, we dedesignated our cash-flow hedge transactions related to our international business resulting in mark-to-market accounting for these transactions going forward.

        The primary components of mark-to-market results are origination gains and gains and losses from risk management and trading activities.

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

        Risk management and trading—mark-to-market represents both realized and unrealized gains and losses from changes in the value of our portfolio, including the effects of changes in valuation adjustments. In addition to our fundamental risk management and trading activities, we also use derivative contracts subject to mark-to-market accounting to manage our exposure to changes in market prices as a result of our gas transportation and storage activities, while in general the underlying physical transactions related to our gas transportation and storage activities are accounted for on an accrual basis. We use other non-trading derivative transactions subject to mark-to-market accounting to manage our exposure to changes in market prices related to our other activities that are accounted for on an accrual basis.

        We discuss the changes in mark-to-market results below. We show the relationship between our mark-to-market results and the change in our net mark-to-market energy asset later in this section.

        Mark-to-market results were as follows:

			Quarter Ended September 30,						Nine Months Ended September 30,
			2008			2007			2008			2007
			(In millions)
Unrealized mark-to-market results
	Origination gains		$	5.3		$	4.3		$	73.8		$	37.4
	Risk management and trading—mark-to-market
		Unrealized changes in fair value		(54.4	)		92.4			243.1			170.0
		Changes in valuation techniques		—			—			—			—
		Reclassification of settled contracts to realized		288.1			(21.3	)		141.2			(189.2	)
	Total risk management and trading—mark-to-market			233.7			71.1			384.3			(19.2	)
Total unrealized mark-to-market*				239.0			75.4			458.1			18.2
Realized mark-to-market				(288.1	)		21.3			(141.2	)		189.2
Total mark-to-market results			$	(49.1	)	$	96.7		$	316.9		$	207.4

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

        Total mark-to-market results decreased $145.8 million during the quarter ended September 30, 2008 compared to the same period of 2007 primarily due to unrealized changes in fair value. The period-to-period variance in unrealized changes in fair value was primarily due to:

•

Net power risk management and trading losses of approximately $231 million primarily driven by:

•

$274 million of losses related to power and transmission in the Northeast, PJM, and ERCOT regions due to unfavorable price movements, execution of transactions to reduce our risk position consistent with changes in our strategy, and execution of those transactions in less liquid market conditions, and

•

offsetting gains of $46 million from our emissions trading activities due primarily to favorable price movements.

        The risk management and trading results were partially offset by:

•

$66 million of gains primarily related to our wholesale and retail gas businesses due to favorable price movements on our net sales of wholesale and retail natural gas, and

•

$18 million of gains related to favorable price movements on certain economic hedges of accrual transactions, primarily gas transportation and storage, that do not qualify for or are not designated as cash-flow hedges.

47

        Total mark-to-market results increased $109.5 million during the nine months ended September 30, 2008 compared to the same period of 2007 primarily due to:

•

higher gains from unrealized changes in fair value of $73.1 million, and

•

an increase in origination gains of $36.4 million. We discuss the increase in origination gains below.

        The $73.1 million increase in gains from unrealized changes in fair value was primarily due to

•

higher gains on open mark-to-market activities, primarily gains of $140 million from our coal and freight businesses,

•

net gains on gas portfolio management and trading of $55 million, partially offset by net losses on power portfolio management and trading of $39 million, and

•

offset by retail and wholesale gas and power losses of approximately $84 million related to the unfavorable impact of certain economic hedges of accrual transactions, primarily gas transportation and storage, that do not qualify for or are not designated as cash-flow hedges.

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

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

Derivative Assets and Liabilities

        Derivative assets and liabilities consisted of the following:

	September 30, 2008			December 31, 2007
	(In millions)
Current Assets	$	1,604.7		$	760.6
Noncurrent Assets		1,006.0			1,030.2
Total Assets		2,610.7			1,790.8
Current Liabilities		1,115.8			1,134.3
Noncurrent Liabilities		1,171.1			1,118.9
Total Liabilities		2,286.9			2,253.2
Net Derivative Position	$	323.8		$	(462.4	)
Composition of net derivative exposure:
Embedded derivative associated with $1 billion preferred stock issued to MidAmerican	$	(46.2	)	$	—
Hedges		(1,215.0	)		(937.6	)
Mark-to-market		1,559.8			673.0
Net cash collateral included in derivative balances		25.2			(197.8	)
Net Derivative Position	$	323.8		$	(462.4	)

        As discussed in our 2007 Annual Report on Form 10-K, our "Derivative assets and liabilities" include contracts accounted for as hedges and those accounted for on a mark-to-market basis. The amounts are presented in our Consolidated Balance Sheets after the impact of netting as required by FSP FIN 39-1, which is discussed in more detail in the Notes to Consolidated Financial Statements beginning on page 30. Due to the impacts of commodity prices, the number of open positions, master netting arrangements, and offsetting risk positions on the presentation of our derivative assets and liabilities in our Consolidated Balance Sheets, we believe an evaluation of the net position is the most relevant measure of the economic exposure and performance of our derivatives, and is discussed in more detail below. However, in order to provide information about how we determine the fair value of derivatives, we present our gross derivatives as required by SFAS No. 157 in the Notes to Consolidated Financial Statements beginning on page 31.

        We determined that the conversion provisions of the Preferred Stock that we issued to MidAmerican constitute an embedded derivative that must be bifurcated from the Preferred Stock and recorded at fair value with changes in fair value recorded in earnings. Accordingly, we recorded a current derivative liability of approximately $46.2 million as the fair value of this conversion feature as of September 30, 2008 and we recorded a corresponding discount on the Preferred Stock. We discuss the Preferred Stock in detail in

48

the Notes to Consolidated Financial Statements beginning on page 21.

        The fair value of this derivative could change substantially in the future based upon discrete factors. The primary factors that could change its value, other than the passage of time and changes in interest rates, are:

•

approval or denial of approval of the merger by shareholders or various regulatory bodies, and

•

the existence and amount of any potential competing bid for the company.

        It is not possible to predict whether these events could occur, but if and when they do, the fair value of the derivative could increase or decrease substantially. Such changes would be recorded in earnings when they occur and could be material. Upon receipt of all approvals necessary to issue 19.9% of the shares of our common stock to a single party, we expect the derivative will be an equity instrument, and we will reclassify the fair value at that time to common shareholders equity and discontinue recording changes in its fair value, in accordance with SFAS No. 133.

        The increase of $277.4 million in our net derivative liability exposure relating to hedges since December 31, 2007 was primarily due to $353 million of losses associated with existing hedge positions due to unfavorable price changes and $267 million of losses associated with hedges entered into during 2008, partially offset by $328 million related to the settlement of out-of-the-money cash-flow hedges during the first nine months of 2008.

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

		Quarter Ended September 30, 2008						Nine Months Ended September 30, 2008
		(in millions)
Fair value beginning of period					$	1,380.1				$	673.0
Changes in fair value recorded in earnings
	Origination gains	$	5.3					$	73.8
	Unrealized changes in fair value		(54.4	)					243.1
	Changes in valuation techniques		—						—
	Reclassification of settled contracts to realized		288.1						141.2
Total changes in fair value						239.0					458.1
Changes in value of exchange-listed futures and options						(124.6	)				418.7
Net change in premiums on options						68.1					75.2
Contracts acquired						—					—
Other changes in fair value						(2.8	)				(65.2	)
Fair value at end of period					$	1,559.8				$	1,559.8

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

•

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

•

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

•

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

•

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

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

•

Changes in value of exchange-listed futures and options are adjustments to remove unrealized revenue from exchange-traded contracts that are included in revenues. The fair value of these contracts is recorded in "Accounts receivable" rather

49

than "Derivative assets" in our Consolidated Balance Sheets because these amounts are settled through our margin account with a third-party broker.

•

Net changes in premiums on options reflects the accounting for premiums on options purchased as an increase in the net derivative asset and premiums on options sold as a decrease in the net derivative asset.

•

Contracts acquired represents the initial fair value of acquired derivative contracts recorded in "Derivative assets and liabilities" in our Consolidated Balance Sheets.

•

Other changes in fair value include transfers of derivative assets and liabilities between accounting methods resulting from the designation and de-designation of cash-flow hedges.

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

        Consistent with the exit price concept, upon adoption we reduced our derivative liabilities to reflect our own credit risk. As a result, during the first quarter of 2008, we recorded a pre-tax reduction in "Accumulated other comprehensive loss" totaling $10 million for the portion related to cash-flow hedges and a pre-tax gain in earnings totaling $3 million for the remainder of our derivative liabilities. All other impacts of adoption were immaterial. We discuss SFAS No. 157 and how we determine fair value in more detail in the Notes to Consolidated Financial Statements beginning on page 31.

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

	Settlement Term
	2008		2009		2010			2011		2012			2013			Thereafter			Fair Value
	(In millions)
Level 1	$	10.9	$	—	$	—		$	—	$	—		$	—		$	—		$	10.9
Level 2		278.6		579.3		(77.5	)		113.3		59.1			(7.7	)		0.2			945.3
Level 3		54.4		161.2		333.7			101.1		(37.5	)		(9.2	)		(0.1	)		603.6
Total net derivative asset subject to mark-to-market accounting	$	343.9	$	740.5	$	256.2		$	214.4	$	21.6		$	(16.9	)	$	0.1		$	1,559.8

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

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

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

        In order to realize the entire value of a long-term contract in a single transaction, we would need to sell or assign the entire contract. If we were to sell or assign any of our long-term contracts in their entirety, we may not realize the entire value reflected in the preceding table.

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Operating Expenses

Our merchant energy business operating expenses decreased $164.1 million during the quarter ended September 30, 2008 compared to the same period of 2007, primarily due to lower performance-based labor and benefits costs at our merchant energy business of $143.0 million and lower nonlabor operating expenses of $21.1 million.

        Our merchant energy business operating expenses decreased $40.0 million during the nine months ended September 30, 2008 compared to the same period of 2007. The decrease was primarily due to lower performance-based labor and benefit costs of $56.1 million, partially offset by higher nonlabor operating expenses of $16.1 million.

Workforce Reduction Costs

In September 2008, our merchant energy business approved a restructuring of the workforce at our Customer Supply operations. We recognized a $2.2 million pre-tax expense during the quarter ended September 30, 2008 related to the elimination of approximately 100 positions associated with this restructuring. We discuss our workforce reduction costs in more detail in the Notes to Consolidated Financial Statements on page 16.

Impairments and Other Costs

During the quarter ended September 30, 2008, our merchant energy business recorded a $462.1 million charge associated with an impairment of our upstream gas assets, our investment in Constellation Energy Partners LLC, and goodwill. We discuss these impairments in more detail in the Notes to Consolidated Financial Statements beginning on page 12. Additionally, we recorded a liability for the anticipated settlement of the fly ash class action litigation of $15.0 million, net of an estimated insurance recovery. We discuss the fly ash litigation settlement in more detail in the Notes to Consolidated Financial Statements on pages 15 and 27.

Merger and Strategic Alternatives Costs

During the quarter ended September 30, 2008, our merchant energy business recorded a $27.2 million pre-tax charge associated with the pending merger with MidAmerican and other strategic alternatives costs. We discuss our merger and strategic alternatives costs in more detail in the Notes to Consolidated Financial Statements on page 12.

Depreciation, Depletion and Amortization Expense

Our merchant energy business incurred higher depreciation, depletion and amortization expenses of $10.1 million during the nine months ended September 30, 2008 compared to the same period of 2007, primarily due to increased depletion expenses related to our upstream natural gas operations as a result of increased drilling and production, partially offset by the cessation of operations at our synfuel facilities in December 2007.

Gains on Sales of Assets

For the nine months ended September 30, 2008, we recognized gains of $91.5 million, including a $14.3 million gain, net of the minority interest gain of $0.7 million, related to the sale of our working interests in oil and natural gas producing wells in Oklahoma to Constellation Energy Partners that was completed in the first quarter of 2008.

        We discuss our gains on sale of assets in more detail in the Notes to Consolidated Financial Statements on page 17.

Regulated Electric Business

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

Results

	Quarter Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In millions)
Revenues	$	822.4		$	778.2		$	1,980.5		$	1,837.3
Electricity purchased for resale expenses		(556.6	)		(522.6	)		(1,416.2	)		(1,117.7	)
Operations and maintenance expenses		(99.0	)		(96.7	)		(291.9	)		(274.9	)
Merger and strategic alternatives costs *		(7.9	)		—			(7.9	)		—
Depreciation and amortization		(39.4	)		(46.8	)		(138.0	)		(140.5	)
Taxes other than income taxes		(36.3	)		(36.1	)		(104.1	)		(105.8	)
Income from Operations	$	83.2		$	76.0		$	22.4		$	198.4
Net Income (Loss)	$	31.7		$	34.3		$	(38.8	)	$	85.9
Other Items Included in Operations (after-tax):
Maryland settlement credit	$	—		$	—		$	(125.3	)	$	—
Effective tax rate impact of Maryland settlement agreement		3.4			—			8.4			—
Merger and strategic alternatives costs *		(7.5	)		—			(7.5	)		—
Total Other Items	$	(4.1	)	$	—		$	(124.4	)	$	—

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 19 provides a reconciliation of operating results by segment to our Consolidated Financial Statements

* Recovery of these costs will not be sought in rates.

        Net income from the regulated electric business decreased $2.6 million during the quarter ended September 30, 2008 compared to the same period in 2007, mostly due to merger and strategic alternatives costs of $7.5 million after-tax partially offset by the impact on the effective tax rate of the Maryland settlement credit of $3.4 million after-tax.

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        Net income from the regulated electric business decreased $124.7 million during the nine months ended September 30, 2008 compared to the same periods in 2007, mostly due to the impact of the Maryland settlement credit of $125.3 million after-tax and the merger and strategic alternatives costs of $7.5 million after-tax. This was partially offset by the favorable impact of reduced earnings from the Maryland settlement agreement on our effective tax rate of $8.4 million for the nine months ended September 30, 2008.

Electric Revenues

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

	Quarter Ended September 30, 2008 vs. 2007			Nine Months Ended September 30, 2008 vs. 2007
	(In millions)
Distribution volumes	$	(4.7	)	$	(9.8	)
Maryland settlement credit		(0.6	)		(188.8	)
Revenue decoupling		8.8			15.8
Standard offer service		22.8			5.9
Rate stabilization credits		4.6			285.4
Rate stabilization recovery		6.5			34.9
Financing credits		(1.0	)		(8.1	)
Senate Bill 1 credits		5.6			(0.4	)
Total change in electric revenues from electric system sales		42.0			134.9
Other		2.2			8.3
Total change in electric revenues	$	44.2		$	143.2

Distribution Volumes

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

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

	Quarter Ended September 30, 2008 vs. 2007			Nine Months Ended September 30, 2008 vs. 2007
Residential		(7.9	)%		(4.9	)%
Commercial		(0.7	)		(3.1	)
Industrial		(4.5	)		(2.2	)

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

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

Maryland Settlement Credit

As discussed in more detail in the Notes to Consolidated Financial Statements on page 23, BGE entered into a settlement agreement with the State of Maryland and other parties, which provided residential electric customers a credit of $170 per customer. The estimated settlement of $188.2 million was accrued in the second quarter of 2008 and $188.8 million was credited to customers in the third quarter of 2008.

Revenue Decoupling

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

Standard Offer Service

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

        Standard offer service revenues increased during the quarter and nine months ended September 30, 2008 compared to the same periods of 2007, mostly due to higher standard offer service rates, partially offset by lower standard offer service volumes.

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Rate Stabilization Credits

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

Rate Stabilization Recovery

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

Financing Credits

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

Senate Bill 1 Credits

As a result of Senate Bill 1, beginning January 1, 2007, we were required to provide to residential electric customers a credit equal to the amount collected from all BGE electric customers for the decommissioning of our Calvert Cliffs nuclear power plant and to suspend collection of the residential return component of the POLR administrative charge collected through residential rates through May 31, 2007. Under an order issued by the Maryland PSC in May 2007, as of June 1, 2007, we were required to reinstate collection of the residential return component of the POLR administration charge in rates and to provide all residential electric customers a credit for the residential return component of the administrative charge. Under the Maryland settlement agreement, which is discussed in more detail on page 23 of Notes to Consolidated Financial Statements, BGE was allowed to resume collection of the residential return portion of the POLR administrative charge from June 1, 2008 through May 31, 2010 without having to rebate it to residential customers.

        The increase in revenues during the quarter ended September 30, 2008 compared to the same period of 2007 is primarily due to the absence of the credit for the residential return component of the administrative charge which was suspended under the Maryland settlement agreement.

Electricity Purchased for Resale Expenses

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

	Quarter Ended September 30,					Nine Months Ended September 30,
	2008		2007			2008		2007
	(In millions)
Actual costs	$	537.7	$	508.4		$	1,372.0	$	1,379.1
Deferral under rate stabilization plan		—		(4.5	)		—		(285.4	)
Recovery under rate stabilization plan		18.9		18.7			44.2		24.0
Electricity purchased for resale expenses	$	556.6	$	522.6		$	1,416.2	$	1,117.7

Actual Costs

BGE's actual costs for electricity purchased for resale increased $29.3 million during the quarter ended September 30, 2008 compared to the same period of 2007, primarily due to higher contract prices to purchase electricity for our customers, partially offset by lower volumes.

        BGE's actual costs for electricity purchased for resale decreased $7.1 million during the nine months ended September 30, 2008 compared to the same period of 2007, primarily due to lower volumes, partially offset by higher contract prices to purchase electricity for our customers.

Deferral under Rate Stabilization Plan

The deferral of the difference between our actual costs of electricity purchased for resale and what we were allowed to bill customers under Senate Bill 1 ended on December 31, 2007. These deferred expenses, plus carrying charges, are included in "Regulatory Assets (net)" in our, and BGE's, Consolidated Balance Sheets.

Recovery under Rate Stabilization Plans

In late June 2007, we began recovering previously deferred amounts from customers related to our first rate stabilization plan. In April 2008, we began recovering previously deferred amounts from customers related to our second rate stabilization plan. During the quarter and nine months ended September 30, 2008, we recovered $18.9 million and $44.2 million, respectively, in deferred electricity purchased for resale expenses. The collections related to the first rate stabilization plan secure the payment of principal and interest and other ongoing costs associated

53

with rate stabilization bonds issued by a subsidiary of BGE in June 2007.

Electric Operations and Maintenance Expenses

Regulated operations and maintenance expenses increased $17.0 million in the nine months ended September 30, 2008 compared to the same period in 2007, mostly due to increased uncollectible accounts receivable expense of $10.0 million and $6.2 million of higher labor and benefit costs and the impact of inflation on other costs.

Electric Depreciation and Amortization

Regulated electric depreciation and amortization expense decreased $7.4 million during the quarter ended September 30, 2008 compared to the same period in 2007, primarily due to revised depreciation rates implemented as of June 1, 2008. As a result of the Maryland settlement agreement, which is discussed in more detail on page 23 of the Notes to Consolidated Financial Statements, BGE implemented revised depreciation rates for regulatory and financial reporting purposes effective June 1, 2008 that are expected to reduce annual depreciation expense by approximately $16 to $18 million for BGE's electric business. The impact of the revised depreciation rates on BGE's electric business for the nine months ended September 30, 2008 was a reduction in depreciation expense of $5.7 million.

Regulated Gas Business

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

Results

	Quarter Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In millions)
Revenues	$	155.5		$	118.7		$	740.0		$	688.8
Gas purchased for resale expenses		(107.5	)		(70.6	)		(505.2	)		(457.6	)
Operations and maintenance expenses		(40.5	)		(38.1	)		(118.0	)		(114.3	)
Merger and strategic alternatives costs*		(3.2	)		—			(3.2	)		—
Depreciation and amortization		(10.1	)		(11.6	)		(33.2	)		(35.3	)
Taxes other than income taxes		(7.8	)		(7.9	)		(26.6	)		(27.0	)
(Loss) Income from operations	$	(13.6	)	$	(9.5	)	$	53.8		$	54.6
Net (Loss) Income	$	(12.2	)	$	(9.8	)	$	24.1		$	18.2
Other Items Included in Operations (after-tax):
Effective tax rate impact of Maryland settlement agreement	$	(1.4	)	$	—		$	2.3		$	—
Merger and strategic alternatives costs*		(3.1	)		—			(3.1	)		—
Total Other Items	$	(4.5	)	$	—		$	(0.8	)	$	—

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 19 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.
* Recovery of these costs will not be sought in rates.

Net loss from the regulated gas business increased $2.4 million during the quarter ended September 30, 2008 compared to the same period of 2007, primarily due to merger and strategic alternatives costs of $3.1 million after-tax and the impact of reduced earnings from the Maryland settlement agreement on our effective tax rate of $1.4 million, partially offset by reduced depreciation and amortization expense of $1.0 million after-tax.

        Net income from the regulated gas business increased $5.9 million during the nine months ended September 30, 2008 compared to the same period of 2007, primarily due to an increase in revenues less gas purchased for resale expenses of $2.4 million after-tax and the impact of reduced earnings from the Maryland settlement agreement on our effective tax rate of $2.3 million.

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Gas Revenues

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

	Quarter Ended September 30, 2008 vs. 2007			Nine Months Ended September 30, 2008 vs. 2007
	(In millions)
Distribution volumes	$	(0.3	)	$	(9.6	)
Base rates		—			(0.1	)
Revenue decoupling		0.4			10.8
Gas cost adjustments		14.6			(1.5	)
Total change in gas revenues from gas system sales		14.7			(0.4	)
Off-system sales		22.4			51.3
Other		(0.3	)		0.3
Total change in gas revenues	$	36.8		$	51.2

Distribution Volumes

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

	Quarter Ended September 30, 2008 vs. 2007			Nine Months Ended September 30, 2008 vs. 2007
Residential		(1.0	)%		(10.3	)%
Commercial		(12.1	)		(5.3	)
Industrial		5.3			10.1

        During the quarter ended September 30, 2008 compared to the same period in 2007, we distributed less gas to residential and commercial customers 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, 2008 compared to the same period in 2007, we distributed less gas to residential and commercial customers due to milder weather and 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.

Base Rates

In December 2005, the Maryland PSC issued an order granting BGE a $35.6 million annual increase in its gas base rates. In December 2006, the Baltimore City Circuit Court upheld the rate order. Certain parties filed an appeal with the Court of Special Appeals. However, in September 2008, the Court of Special Appeals upheld the rate order.

Revenue Decoupling

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

Gas Cost Adjustments

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

        Gas cost adjustment revenues increased $14.6 million during the quarter ended September 30, 2008 compared to the same period of 2007, primarily due to higher prices, partially offset by less gas sold.

        Gas cost adjustment revenues decreased $1.5 million during the nine months ended September 30, 2008 compared to the same period of 2007 because we sold less gas, partially offset by higher prices.

Off-System Gas Sales

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

        Revenues from off-system gas sales increased during the quarter ended September 30, 2008 compared to the same period of 2007 because the gas we sold off-system was at higher prices, partially offset by less gas sold.

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

Gas Purchased For Resale Expenses

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

        Gas costs increased $36.9 million during the quarter ended September 30, 2008 compared to the same period of 2007 because we purchased gas at higher prices, partially offset by lower volumes.

        Gas costs increased $47.6 million during the nine months ended September 30, 2008 compared to the same period of 2007 because we purchased gas at higher prices, partially offset by lower volumes.

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Gas Operations and Maintenance Expenses

Gas operations and maintenance expenses increased $2.4 million in the quarter ended September 30, 2008 compared to the same period in 2007, mostly due to increased uncollectible accounts receivable expense of $2.4 million.

        Gas operations and maintenance expenses increased $3.7 million in the nine months ended September 30, 2008 compared to the same period in 2007, mostly due to increased uncollectible accounts receivable expense of $4.1 million.

Gas Depreciation and Amortization

As a result of the Maryland settlement agreement, which is discussed in more detail on page 23 of Notes to Consolidated Financial Statements, BGE implemented revised depreciation rates for regulatory and financial reporting purposes effective June 1, 2008 that are expected to reduce annual depreciation expense by approximately $6 million for its gas business. The impact of the revised depreciation rates on BGE's gas business for the nine months ended September 30, 2008 was a reduction in depreciation expense of $2.0 million.

Other Nonregulated Businesses

Results

	Quarter Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In millions)
Revenues	$	50.2		$	55.0		$	175.5		$	174.5
Operating expense		(29.4	)		(41.4	)		(128.4	)		(114.5	)
Merger and strategic alternatives costs		(0.9	)		—			(0.9	)		—
Depreciation and amortization		(16.2	)		(13.0	)		(45.5	)		(40.0	)
Taxes other than income taxes		(1.2	)		(0.6	)		(2.3	)		(1.9	)
Income (Loss) from Operations	$	2.5		$	—		$	(1.6	)	$	18.1
Net Income	$	0.8		$	(0.3	)	$	0.3		$	9.9
Other Items Included in Operations (after-tax):
Merger and strategic alternatives costs	$	(0.9	)	$	—		$	(0.9	)	$	—

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

        Net income decreased $9.6 million during the nine months ended September 30, 2008 compared to the same period of 2007 primarily because the first quarter of 2007 included a gain related to a sale of a leasing arrangement that did not occur in 2008.

Consolidated Nonoperating Income and Expenses

Gains on Sale of CEP LLC Equity

Gains on sale of CEP LLC Equity decreased $39.2 million and $52.1 million for the quarter and nine months ended September 30, 2008, respectively, as CEP LLC, an equity investment of Constellation Energy, did not sell additional equity in 2008 as it had in the second and third quarters of 2007.

Other (Expense) Income

Other (expense) income decreased during the quarter and nine months ended September 30, 2008 compared to the same periods of 2007 mostly due to lower interest and investment income as a result of a lower average cash balance and an increase in other-than-temporary impairment charges related to our nuclear decommissioning trust fund assets of $29.2 million for the quarter ended September 30, 2008 and $39.1 million for the nine months ended September 30, 2008.

        Other income at BGE increased $4.2 million during the nine months ended September 30, 2008 compared to the same period of 2007 primarily due to an increase in equity funds capitalized on increased construction work in progress in 2008.

Fixed Charges

Our fixed charges increased during the quarter and nine months ended September 30, 2008 compared to the same periods of 2007 mostly due to a higher level of interest expense associated with the new debt issuances in June 2008, partially offset by higher capitalized interest and allowance for borrowed funds used during construction. We discuss our long-term debt financings in more detail in the Notes to Consolidated Financial Statements on page 21.

        Fixed charges at BGE increased during the quarter and nine months ended September 30, 2008 compared to the same periods of 2007 mostly due to interest expense recognized on the rate stabilization bonds that were issued in June 2007 and the Senior Notes issued in June 2008. We discuss BGE's long-term debt financings in more detail in the Notes to Consolidated Financial Statements on page 21.

Income Taxes

Our income tax expense decreased $275.9 million during the quarter ended September 30, 2008 and $187.0 million during the nine months ended September 30, 2008 compared to the same periods of 2007 mostly due to a decrease in income before income taxes, partially offset by the absence of synthetic fuel tax credits, which expired in 2007.

        During the quarter ended September 30, 2008, BGE's income tax expense increased $4.6 million, primarily due to higher pre-tax income, which included the impact of

56

approximately $11 million in merger and strategic alternatives costs, substantially all of which are not tax deductible. During the nine months ended September 30, 2008, BGE's income tax expense decreased $65.8 million, primarily due to lower pre-tax income as a result of the $188 million Maryland settlement credit recorded in the second quarter of 2008. We discuss the Maryland settlement agreement in more detail in the Notes to Consolidated Financial Statements on page 23.

Defined Benefit Plans Expense and Funded Status

Our actual return on qualified pension plan assets was a loss of 16.9% for the nine months ended September 30, 2008 as compared to our assumption of an expected annual return on pension plan assets of 8.75% for the purpose of computing annual net periodic pension cost in accordance with SFAS No. 87, Employers' Accounting for Pensions. This loss reflects the substantial declines in financial markets experienced through the first nine months of 2008. As disclosed in Note 7 of our 2007 Annual Report on Form 10-K, we determine the expected return on pension plan assets component of our annual pension expense using a market-related value of pension plan assets that recognizes asset gains and losses over a five-year period. As a result, the losses incurred during the first nine months of 2008 would increase our annual pension expense beginning in 2009. In addition, a lower fair value of our pension plan assets would result in an increase in our unfunded pension obligation at December 31, 2008 and a related after-tax charge to "Accumulated other comprehensive loss" in accordance with SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans.

        In addition to the losses experienced on our pension plan assets for the nine months ended September 30, 2008, there has also been an overall increase in the level of interest rates, which will impact the discount rate used to determine our defined benefit plan liabilities. In accordance with SFAS No. 87, Employers' Accounting for Pensions, and SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, we are currently using a 6.25% discount rate assumption, which is based on interest rate levels at December 31, 2007, to determine our 2008 pension and postretirement benefit expense. The next time we will update our discount rate assumption will be at December 31, 2008. That updated assumption will impact 2009 annual pension and postretirement benefits expense and the funded status of our pension and postretirement benefit plans at December 31, 2008. Based on interest rate levels at September 30, 2008, our discount rate assumption would increase from 6.25% to 7.50% and have the result of reducing 2009 pension and postretirement benefits expense and improving the funded status of those plans at December 31, 2008.

        Assuming that our qualified pension plan assets earn approximately 2.2% in the fourth quarter (one-fourth of our expected annual asset return of 8.75%) and that interest rate levels remain unchanged between September 30, 2008 and December 31, 2008, we estimate that:

•

our 2009 pension and postretirement benefit plan expense would decrease by approximately $10 million pre-tax, and

•

our unfunded defined benefit plan obligation at December 31, 2008 would increase by approximately $65 million and we would record an after-tax charge to equity of approximately $40 million.

        Since September 30, 2008, our pension plan assets have experienced further losses. However, our actual 2009 pension and postretirement benefits expense and December 31, 2008 funded status of our defined benefit plans will reflect the impact of actual asset returns for the year 2008 and actual interest rate levels at December 31, 2008. Therefore, those amounts could be materially different from the estimates above as of September 30, 2008. Actual asset returns and interest rate levels may also materially impact the level of our contributions to our qualified pension plans in 2009 and subsequent years.

57

Financial Condition

Cash Flows

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

			2008 Segment Cash Flows									Consolidated Cash Flows
			Nine Months Ended September 30, 2008									Nine Months Ended September 30,
			Merchant			Regulated			Other			2008			2007
			(In millions)
Operating Activities
	Net income (loss)		$	105.9		$	(14.7	)	$	0.3		$	91.5		$	563.4
	Non-cash adjustments to net income			437.6			239.1			53.1			729.8			248.7
	Changes in working capital:
		Derivative assets and liabilities, excluding collateral		(931.4	)		—			(3.6	)		(935.0	)		(78.9	)
		Net collateral and margin		(571.2	)		2.6			—			(568.6	)		109.8
		Other changes		(312.9	)		12.0			(57.7	)		(358.6	)		(172.9	)
	Defined benefit obligations*			—			—			—			(34.2	)		(48.0	)
	Other			64.7			(41.0	)		27.4			51.1			(5.4	)
Net cash (used in) provided by operating activities				(1,207.3	)		198.0			19.5			(1,024.0	)		616.7
Investing Activities
	Investments in property, plant and equipment			(986.1	)		(314.9	)		(59.5	)		(1,360.5	)		(920.3	)
	Acquisitions, net of cash acquired			(309.4	)		—			(7.1	)		(316.5	)		(344.1	)
	Contributions to nuclear decommissioning trust funds			(18.7	)		—			—			(18.7	)		(8.8	)
	Sales of investments and other assets			14.4			—			—			14.4			5.6
	Sales of property, plant and equipment			212.8			12.9			1.1			226.8			—
	Contract and portfolio acquisitions			—			—			—			—			(474.2	)
	Issuance of loans receivable			—			—			—			—			(19.0	)
	Repayments of loans receivable			26.0			—			—			26.0			31.9
	Decrease (increase) in restricted funds			2.7			(5.4	)		11.0			8.3			(26.5	)
	Other			(2.6	)		—			(1.5	)		(4.1	)		(70.8	)
Net cash used in investing activities				(1,060.9	)		(307.4	)		(56.0	)		(1,424.3	)		(1,826.2	)
Cash flows from operating activities less cash flows from investing activities			$	(2,268.2	)	$	(109.4	)	$	(36.5	)		(2,448.3	)		(1,209.5	)
Financing Activities*
	Net issuance (repayment) of debt (includes $1 billion proceeds from MidAmerican)												3,041.8			(93.0	)
	Debt issuance costs												(50.6	)		—
	Proceeds from issuance of common stock												17.6			47.7
	Common stock dividends paid												(250.7	)		(226.8	)
	Reacquisition of common stock												(16.2	)		(114.4	)
	Proceeds from contract and portfolio acquisitions												—			847.8
	Other												44.5			10.8
Net cash provided by financing activities													2,786.4			472.1
Net increase (decrease) in cash and cash equivalents												$	338.1		$	(737.4	)

* 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 to the current period presentation.

Cash Flows from Operating Activities

Cash used in operating activities was $1,024.0 million in the first nine months of 2008 compared to a $616.7 million source in 2007. This $1,640.7 million increased use of cash was primarily due to the following changes in working capital:

•

a $856.1 million increase associated with changes in our derivative assets and liabilities (excluding the impact of net collateral posted) that are subject to mark-to-market accounting. We analyze the change in our net mark-to-market derivative assets and liabilities in the Derivative Assets and Liabilities section beginning on page 48.

58

•

a $678.4 million increase in total net cash collateral posted (including initial and variation margin posted with exchanges) during the nine months ended September 30, 2008 compared to the same period of 2007. Most of this increase is due to the $568.6 million in total net cash collateral posted in 2008 as follows:

	(In millions)
Net collateral and margin posted, December 31, 2007	$	(485.3	)
Return of collateral held associated with nonderivative contracts		(18.9	)
Additional collateral posted associated with nonderivative contracts *		(141.7	)
Additional initial and variation margin posted on exchange-traded transactions recorded in accounts receivable		(185.0	)
Additional fair value net cash collateral posted (netted against derivative assets / liabilities) **		(223.0	)
Change in net collateral and margin posted		(568.6	)
Net collateral and margin posted, September 30, 2008	$	(1,053.9	)

* Includes approximately $130 million of additional collateral posted due to certain counterparties that would not accept letters of credit issued by certain financial institutions.
** We discuss our netting of fair value collateral with our derivative assets / liabilities in more detail in the Notes to Consolidated Financial Statements beginning on page 30.

        The $568.6 million increase in net collateral and margin posted during the nine months ended September 30, 2008 primarily reflects the following:

•

increases in commodity prices and the level of our open positions,

•

increases in amounts posted to exchanges to meet initial margin requirements and changes in the rules governing exchange margin requirements, and

•

additional collateral posted in the third quarter following our credit rating downgrades. We discuss our security ratings in more detail below. We discuss our downgrade collateral requirements in more detail on page 62.

        During the quarter ended September 30, 2008, total net collateral posted was a use of cash of approximately $1.1 billion. We discuss all forms of collateral in terms of their impact on our net available liquidity in the Available Sources of Funding section on page 61.

Cash Flows from Investing Activities

Cash used in investing activities was $1,424.3 million in 2008 compared to $1,826.2 million in 2007. The $401.9 million decrease in cash used in 2008 compared to 2007 was primarily due to the absence of $474.2 million in contract and portfolio acquisitions in 2008.

Cash Flows from Financing Activities

Cash provided by financing activities was $2,786.4 million in the first nine months of 2008 compared to $472.1 million in 2007. The increase in cash provided by financing activities of $2,314.3 million was primarily due to:

•

a $1,207.5 million increase in short-term borrowings,

•

a $1,452.8 million net increase in proceeds from the issuance of long-term debt, including the receipt of $1 billion from preferred stock issued to MidAmerican, and

•

a $474.5 million decrease in cash used for the repayment of long-term debt.

        These increases were partially offset by the absence of cash received from contract and portfolio acquisitions in 2007 of $847.8 million.

Security Ratings

Independent credit-rating agencies rate Constellation Energy's and BGE's fixed-income securities. The ratings indicate the agencies' assessment of each company's ability to pay interest, distributions, dividends, and principal on these securities. These ratings affect how much it will cost each company to sell these securities and, in certain cases, the company's ability to access the markets to sell securities. Generally, the better the rating, the lower the cost of the securities to each company when they sell them. A reduction in our credit ratings could have an adverse effect on our access to liquidity sources, increase our cost of funds, trigger additional collateral requirements, and/or decrease the number of investors and counterparties willing to transact with us.

        The factors that credit rating agencies consider in establishing Constellation Energy's and BGE's credit ratings include, but are not limited to, cash flows, liquidity, business risk profile, stock price volatility, political, legislative and regulatory risk, and the level of debt relative to operating cash flows and to total capitalization.

        During the third quarter of 2008, both Constellation Energy's and BGE's senior unsecured debt was downgraded one level by all three credit rating agencies.

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        At the date of this report, our credit ratings were as follows:

		Standard & Poors Rating Group		Moody's Investors Service		Fitch- Ratings
Constellation Energy
	Commercial Paper		A-2		P-2		F2
	Senior Unsecured Debt		BBB		Baa2		BBB
BGE
	Commercial Paper		A-2		P-2		F2
	Senior Unsecured Debt		BBB		Baa2		A-
	Rate Stabilization Bonds*		AAA		Aaa		AAA
	Trust Preferred Securities		BB+		Baa3		BBB+
	Preference Stock		BB+		Ba1		BBB+

* Bonds issued by RSB BondCo LLC, a subsidiary of BGE

        The ratings in the above table reflect the following outlooks by the credit rating agencies:

•

Standard & Poors Rating Group—Watch Developing

•

Moody's Investors Service—Under review for possible downgrade

•

FitchRatings—Stable

        We remain committed to maintaining a stable investment grade credit profile and to meeting our liquidity requirements. We discuss our available sources of funding in more detail below. As a result of the unprecedented events of 2008, we have made substantial changes in our strategy to maintain and improve our credit profile, including focusing on the following immediate goals:

•

reducing the capital requirements, economic risk and collateral needs of our Global Commodities and Customer Supply operations,

•

executing strategic initiatives for our Global Commodities business, which we discuss in more detail on page 41,

•

anticipating closing in November 2008 on a new credit facility of approximately $1.2 billion, and

•

obtaining necessary approvals and executing other activities to close our merger with MidAmerican.

        While management believes that the actions above will be sufficient to meet our liquidity requirements, if we cannot successfully execute on our strategies, our available liquidity would be negatively affected, which would have a material adverse effect on our business, results of operations and financial condition.

        We discuss the impact of our security ratings on our liquidity in more detail on page 62.

Available Sources of Funding

We continuously monitor our liquidity requirements. We rely on the capital and commercial paper markets, and credit facilities, to meet our liquidity needs. However, the current disruptions in the credit and capital markets as well as counterparty concerns about our financial condition have made it more difficult for us to raise capital and access credit necessary to provide sufficient liquidity to meet our business requirements.

        We fund our short-term working capital needs with existing cash and with our credit facilities, which support direct cash borrowings and the issuance of commercial paper. We also use our credit facilities to support the issuance of letters of credit, primarily for our merchant energy business.

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

Constellation Energy

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

•

$3.85 billion expiring July 2012

•

$250 million expiring December 2008

•

$750 million expiring December 2008

•

$380 million expiring December 2008

•

$150 million expiring December 2009

•

$350 million expiring September 2013

        These facilities collectively support the issuance of letters of credit and/or cash borrowings up to $5.7 billion. In late September, we were unable to issue commercial paper to replace maturing commercial paper and meet other obligations. Instead, we fully drew on our $750 million credit facility to secure funds. During the third quarter, Constellation Energy issued net incremental commercial paper of $164.8 million, which brought the total commercial paper outstanding at September 30, 2008 to $310.5 million. During the month of October, Constellation Energy repaid $294.0 million of this outstanding balance as the commercial paper matured. The remainder of Constellation Energy's currently outstanding commercial paper will mature within the month of November. We expect to continue to utilize commercial paper as a primary source of short-term debt if market conditions return to normal.

BGE

BGE currently maintains a $400.0 million five-year revolving credit facility expiring in 2011. BGE can use the facility to issue letters of credit or to issue short-term debt through the issuance of commercial paper or through direct borrowing against the facility. In October, in response to the temporary lack of liquidity in the commercial paper market, BGE drew $270 million on its $400 million credit facility to secure funds in advance of maturing commercial paper and other obligations.

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        During the course of the third quarter, BGE issued net incremental commercial paper of $189.0 million, which represents BGE's total commercial paper outstanding at September 30, 2008. During the month of October, BGE repaid $171.7 million of this outstanding balance as the commercial paper matured. BGE's currently outstanding commercial paper will fully mature within the month of November. We expect to utilize commercial paper as a primary source of short-term debt if market conditions return to normal.

Net Available Liquidity

	As of June 30, 2008
	Constellation Energy			BGE			Total Consolidated
	(In millions)
Credit facilities	$	5,730		$	400		$	6,130
Less: Letters of credit issued		(4,328	)		(1	)		(4,329	)
Less: Cash drawn on credit facilities		—			—			—
Undrawn facilities		1,402			399			1,801
Less: Commercial paper outstanding		(146	)		—			(146	)
Net available facilities		1,256			399			1,655
Add: Cash		1,216			15			1,231
Net available liquidity	$	2,472		$	414		$	2,886

	As of September 30, 2008
	Constellation Energy			BGE			Total Consolidated
	(In millions)
Credit facilities	$	5,730		$	400		$	6,130
Less: Letters of credit issued		(3,979	)		(1	)		(3,980	)
Less: Cash drawn on credit facilities		(750	)		—			(750	)
Undrawn facilities		1,001			399			1,400
Less: Commercial paper outstanding		(311	)		(189	)		(500	)
Net available facilities		690			210			900
Add: Cash		1,423			11			1,434
Net available liquidity	$	2,113		$	221		$	2,334

        Net available liquidity decreased during the third quarter of 2008 by approximately $0.5 billion, primarily due to:

•

an increase in total net collateral posted (including initial and variation margin posted with exchanges) of $1.1 billion, primarily reflecting the return of collateral previously held by us to other parties as a result of the effect of falling commodity prices on positions we held with these counterparties, and

•

a $0.7 billion increase in cash used for working capital (excluding collateral and margin requirements).

        These decreases were offset by

•

the receipt of $1.0 billion proceeds from the issuance of preferred stock to MidAmerican, and

•

a $0.3 billion reduction in letters of credit issued.

	As of October 31, 2008 (estimated)
	Constellation Energy			BGE			Total Consolidated
	(In millions)
Credit facilities	$	5,730		$	400		$	6,130
Less: Letters of credit issued		(3,977	)		(1	)		(3,978	)
Less: Cash drawn on credit facilities		(750	)		(270	)		(1,020	)
Undrawn facilities		1,003			129			1,132
Less: Commercial paper outstanding		(17	)		(18	)		(35	)
Net available facilities		986			111			1,097
Add: Cash		719			59			778
Net available liquidity	$	1,705		$	170		$	1,875

        We discuss strategic initiatives to improve our liquidity in detail beginning on page 62.

Collateral

Constellation Energy's collateral requirements arise from its merchant energy business' need to participate in certain organized markets, such as Independent System Operators (ISOs) or financial exchanges as well as from our goal of remaining economically hedged in our power and gas customer supply businesses, third party coal business and our trading activities. To support wholesale and retail power customer supply business obligations, as well as some trading activities, Constellation Energy posts collateral to ISOs. Forward hedging of our Generation and Customer Supply activities' obligations, as well as our Global Commodities trading activities, creates the need to transact with exchanges such as NYMEX, ICE and NOS. We post initial margin based on exchange rules, as well as variation margin related to the change in value of the net open position with the exchange. Constellation Energy's initial margin requirements increased during the third quarter as a result of changes in exchange rules. Daily variation margin postings to each exchange depend on price moves in the underlying power, gas and coal exchange traded forward and option contracts.

        In addition to the collateral posted to ISOs and exchanges, we post collateral with certain counterparties. These collateral amounts may be fixed or may vary with price levels.

        There are certain asymmetries relating to the use of collateral that create liquidity requirements for our merchant energy businesses. These asymmetries arise as a result of our actions to be economically hedged and market conditions or conventions for conducting business that

61

result in some transactions being collateralized while others are not, including:

•

In our third party coal business, we generally buy coal from suppliers that do not post collateral, but we enter into physical or financial sales contracts that require us to post collateral.

•

In our Customer Supply activities, we generally do not receive collateral under contractual obligations to supply power or gas to our customers but our Global Commodities operation hedges these transactions through purchases of power and gas that generally require us to post collateral.

•

In our Generation activities, we may have to post collateral on our power sale or fuel purchase contracts, but our generating plants are not a source of collateral.

        In an environment of stable commodity prices, Constellation Energy's net collateral position is relatively stable. However, during the six months ended June 30, 2008 and nine months ended September 30, 2008, the energy markets were affected by large fluctuations in commodity prices:

Increases (decreases)	Six months ended June 30, 2008			Nine months ended September 30, 2008
Power		33	%		(8	)%
Natural gas		44	%		(5	)%
Coal		153	%		58	%
Crude oil		55	%		1	%

        This price variability led to an increase in collateral held during the first six months of 2008 and our need to return and post additional collateral for the quarter ended September 30, 2008.

        Customers of our merchant energy business rely on the creditworthiness of Constellation Energy. In this regard, we have certain agreements that contain provisions that would require additional collateral upon a credit rating decrease in the senior unsecured debt of Constellation Energy. A decline below investment grade by Constellation Energy may require us, under the terms of our counterparty contracts, to post additional collateral to provide necessary credit support for our merchant energy business' forward obligations. Based on contractual provisions at September 30, 2008, we estimate that if Constellation Energy's senior unsecured debt were downgraded we would have the following additional collateral obligations:

Credit Ratings Downgraded to *	Level Below Current Rating		Incremental Obligations		Cumulative Obligations
	(In millions)
BBB-/Baa3		1	$	171	$	171
BB+/Ba1 (Below investment grade)		2		2,204		2,375

* If there are split ratings among the independent credit-rating agencies, the lowest credit rating is used to determine our incremental collateral obligations.

        The estimated collateral obligation amounts above have declined compared to those reported in our quarterly report on Form 10-Q for the quarter ended June 30, 2008. This decrease is due to changes in open positions, price movements, and posting of additional collateral requirements resulting from our credit ratings being downgraded in the third quarter of 2008. As of October 31, 2008, incremental downgrade collateral postings for a one level and two level downgrade have changed to $178 million and $1,865 million, respectively. As a result, the cumulative obligation for a two level downgrade is $2,043 million.

        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 obligation amounts specified above, which could be material. We discuss our credit ratings in the Security Ratings section beginning on page 59 and in our 2007 Annual Report on Form 10-K. We discuss our credit facilities in the Available Sources of Funding section beginning on page 60.

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

        The credit agreement of BGE contains a provision requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At September 30, 2008, the debt to capitalization ratio for BGE as defined in this credit agreement was 54%.

        Decreases in Constellation Energy's or BGE's credit ratings would not trigger an early payment on any of their credit facilities.

Strategic Initiatives to Improve Liquidity

We anticipate closing in November 2008 on a new credit facility of approximately $1.2 billion. In early November 2008, we also executed agreements with MidAmerican that provide us the option to sell one or both of the following assets to MidAmerican for aggregate proceeds of $350 million:

•

our equity interest in Safe Harbor Water Power Corporation, a 417 MW hydroelectric generating facility located in Pennsylvania, and

•

our West Valley generating plant, a 200 MW electric generating facility located in Utah.

        The agreements are expected to become effective by November 14, 2008, provided that MidAmerican has approved certain disclosure schedules related to each agreement, and expire upon the earlier of the sale of the assets, the closing of the merger, or November 6, 2009.

        Upon exercise of an option, Constellation Energy's subsidiary will enter into a purchase agreement for the sale of the asset to MidAmerican and Constellation Energy will

62

guarantee its subsidiary's obligations under the purchase agreement. The closing of the sale, including payment of the purchase price to Constellation Energy, will be subject to customary closing conditions, including receipt of required regulatory approvals.

        In addition to these efforts, we are actively seeking to increase available liquidity and to reduce our business risk. Specifically, we are reducing capital spending and ongoing expenses, scaling down the expected variability in long-term earnings and short-term collateral usage, and limiting our exposure to business activities that require contingent capital support. We have announced strategic initiatives including efforts to sell our upstream gas properties, our international business, which includes our coal sourcing, freight, uranium, power, natural gas and emissions marketing activities outside North America, and our gas trading activities.

        Collectively, we believe these efforts will provide sufficient liquidity to manage our business and successfully close the pending merger with MidAmerican. However, if market factors prevent us from successfully executing our plan or we are otherwise unable to successfully execute our plan, our liquidity would be adversely affected, which would have a material adverse effect on our business, results of operations, and financial condition.

Capital Resources

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

        We will continue to have cash requirements for:

•

working capital needs,

•

payments of interest, distributions, and dividends,

•

capital expenditures, and

•

the retirement of debt and redemption of preference stock.

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

•

regulation, legislation, and competition,

•

BGE load requirements,

•

environmental protection standards,

•

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

•

the effect of market conditions on those projects,

•

the cost and availability of capital,

•

the availability of cash from operations, and

•

business decisions to invest in capital projects.

        Our estimates are also subject to additional factors. Please see the Forward Looking Statements section beginning on page 74 and Item 1A. Risk Factors section beginning on page 68. We discuss the potential impact of environmental legislation and regulation in more detail in Business Environment section on page 37 and Item 1. Business—Environmental Matters section of our 2007 Annual Report on Form 10-K.

Calendar Year Estimates			2008		2009
			(In millions)
Nonregulated Capital Requirements:
	Merchant energy
		Generation plants	$	710	$	510
		Environmental controls		530		270
		Portfolio acquisitions/investments		160		—
		Technology/other		105		125
		Nuclear fuel		200		270
	Total merchant energy capital requirements			1,705		1,175
	Other nonregulated capital requirements			95		50
Total nonregulated capital requirements				1,800		1,225
Regulated Capital Requirements:
	Regulated electric			395		400
	Regulated gas			75		75
Total regulated capital requirements				470		475
Total capital requirements			$	2,270	$	1,700

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 EPA, Maryland, and Pennsylvania environmental regulations and legislation, and

•

enhancements to our information technology infrastructure.

Regulated Electric and Gas

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

Funding for Capital Requirements

We discuss our funding for capital requirements in our 2007 Annual Report on Form 10-K. The current disruptions in the credit and capital markets as well as counterparty concerns about our financial condition have made it more difficult for us to raise capital and access credit necessary to provide sufficient liquidity to meet our business requirements. We discuss our available sources of funding beginning on page 60 and our strategy beginning on page 36.

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Contractual Payment Obligations and Committed Amounts

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

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

			Payments
			2008		2009- 2010		2011- 2012		There- after		Total
			(In millions)
Contractual Payment Obligations
Long-term debt:1
	Nonregulated
		Principal	$	0.7	$	1,501.9	$	749.8	$	2,288.7	$	4,541.1
		Interest		70.3		493.1		311.2		3,610.8		4,485.4
	Total			71.0		1,995.0		1,061.0		5,899.5		9,026.5
	BGE
		Principal		90.5		121.6		254.2		1,889.4		2,355.7
		Interest		42.5		264.6		246.4		1,423.8		1,977.3
	Total			133.0		386.2		500.6		3,313.2		4,333.0
BGE preference stock				—		—		—		190.0		190.0
Operating leases2				100.5		548.0		375.9		690.2		1,714.6
Purchase obligations:3
	Purchased capacity and energy4			132.0		674.9		257.6		280.1		1,344.6
	Fuel and transportation			598.1		1,995.0		741.3		1,125.3		4,459.7
	Other			210.1		63.1		21.2		43.1		337.5
Other noncurrent liabilities:
	FIN 48 tax liability			—		2.7		30.1		12.9		45.7
	Pension benefits5			1.2		200.2		162.9		—		364.3
	Postretirement and postemployment benefits6			10.2		84.2		98.8		299.0		492.2
Total contractual payment obligations			$	1,256.1	$	5,949.3	$	3,249.4	$	11,853.3	$	22,308.1

1

Amounts in long-term debt reflect the original maturity date. Investors may require us to repay $339.8 million early through put options and remarketing features. Interest on variable rate debt is included based on the forward curve for interest rates.

2

Our operating lease commitments include future payment obligations under certain power purchase agreements as discussed further in Note 11 of our 2007 Annual Report on Form 10-K.

3

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

4

Our contractual obligations for purchased capacity and energy are shown on a gross basis for certain transactions, including both the fixed payment portions of tolling contracts and estimated variable payments under unit-contingent power purchase agreements.

5

Amounts related to pension benefits reflect our current 5-year forecast of contributions for our qualified pension plans and participant payments for our nonqualified pension plans. Refer to Note 7 of our 2007 Annual Report on Form 10-K for more detail on our pension plans.

6

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

Off-Balance Sheet Arrangements

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

        At September 30, 2008, Constellation Energy had a total face amount of $17,870.9 million in guarantees outstanding, of which $16,567.2 million related to our merchant energy business. These amounts generally do not represent incremental consolidated Constellation Energy obligations; rather, they primarily represent parental guarantees of certain subsidiary obligations to third parties in order to allow our subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Our estimated net exposure for obligations under commercial transactions covered by these guarantees was approximately $3.8 billion at September 30, 2008, which represents the total amount the parent company could be required to fund based on September 30, 2008 market prices. For those guarantees related to our derivative liabilities, the fair value of the obligation is recorded in our Consolidated Balance Sheets. We believe it is unlikely that we would be required to perform or incur any losses associated with guarantees of our subsidiaries' obligations.

        We discuss our other guarantees in the Notes to Consolidated Financial Statements on page 26.

Market Risk

Commodity Risk

We use value at risk to measure the sensitivity of the value of mark-to-market energy contracts of our Global Commodities operation to potential changes in market prices. Value at risk represents the potential pre-tax loss in the fair value of these derivative 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 2007 Annual Report on Form 10-K. The table on the next page is the value at risk associated with our Global Commodities operation's derivative assets and liabilities subject to mark-to-market accounting, including both trading and non-trading activities.

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        We discuss our mark-to-market results in more detail in the Mark-to-Market section beginning on page 46.

		Quarter Ended September 30, 2008
		(In millions)
99% Confidence Level, One-Day Holding Period
	Average	$	33.0
	High		39.0
95% Confidence Level, One-Day Holding Period
	Average		25.1
	High		29.7
95% Confidence Level, Ten-Day Holding Period
	Average		79.5
	High		93.9

        Trading activities are included within, and are a subset of, our Global Commodities operation's derivative assets and liabilities subject to mark-to-market accounting. The following table details our value at risk for the trading portion of these derivative assets and liabilities over a one-day holding period at a 99% confidence level for the third quarter of 2008:

	Quarter Ended September 30, 2008
	(In millions)
Average	$	23.7
High		27.0

        In connection with efforts to improve our liquidity, beginning in September 2008, we began to reduce the risk associated with and scale down the size of our risk management and trading portfolio. The results of these efforts are reflected in the decline to a $22.4 million average value at risk for the trading portion of our Global Commodities operation's derivative assets and liabilities subject to mark-to-market accounting over a one-day holding period at a 99% confidence level for the month ended October 31, 2008.

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

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

Wholesale Credit Risk

Credit risk is the risk of loss due to a counterparty's default. Constellation extends credit to counterparties through derivative transactions and other forward contracts that require future settlement either by delivery of the underlying commodity or by cash payment based upon the fair value of that commodity at the time of settlement. We estimate our credit risk based upon an assessment of the probability that a counterparty will default and the expected size of the loss if a default event were to occur.

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

		September 30, 2008			December 31, 2007
Rating
	Investment Grade1		33	%		44	%
	Non-Investment Grade		26			7
	Not Rated		41			49

1

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

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

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

	September 30, 2008			December 31, 2007
Investment Grade Equivalent		47	%		62	%
Non-Investment Grade		53			38

        The credit quality of our wholesale credit portfolio has improved at September 30, 2008 compared to June 30, 2008. Declining global commodity prices have decreased our exposure to the coal and freight businesses which traditionally have a lower credit rating. We discuss the impact of commodity price decreases in more detail beginning on page 38. However, despite the improvement in the third quarter, the percentage of our portfolio

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considered to be investment grade equivalent continues to lag behind the year-end 2007 level.

        By location, approximately 72% of our wholesale credit risk exposure is with domestic (U.S. and Canada) counterparties, and 28% is with international counterparties, which includes exposure to emerging markets such as Indonesia.

        Our estimated total exposure, net of collateral, to counterparties across our entire wholesale portfolio, which includes contracts accounted for using the mark-to-market, hedge, and accrual methods of accounting, is approximately $6.3 billion as of September 30, 2008. The top ten counterparties account for approximately 42% of our total exposure.

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

        Approximately $2.8 billion of our total wholesale credit exposure, net of collateral, of $6.3 billion, is recorded at fair value in our Consolidated Balance Sheets. This $2.8 billion primarily relates to open energy commodity positions from our Global Commodities operation that are accounted for using mark-to-market accounting, derivatives that qualify for designation as hedges under SFAS No. 133, and amounts owed by wholesale counterparties for transactions that settled but have not yet been paid.

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

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
	(In millions)
Investment grade	$	978	$	44	$	934		—	$	—
Split rating		64		4		60		—		—
Non-investment grade		1,107		77		1,030		1		950
Internally rated—investment grade		261		4		257		—		—
Internally rated—non-investment grade		575		9		566		—		—
Total	$	2,985	$	138	$	2,847		1	$	950

        The $950 million exposure in the table above is in the coal sector and represents an approximately $800 million decrease as compared to our exposure at June 30, 2008. The reduction in this exposure primarily reflects the decline in coal prices during the third quarter of 2008.

        Due to the possibility of extreme volatility in the prices of energy commodities and derivatives, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, fail to deliver the electricity for which our Global Commodities operation had contracted), we could incur a loss that could have a material impact on our financial results. We discuss our actual credit losses in more detail in the Global Commodities section on page 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 2007 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 in the Notes to Consolidated Financial Statements beginning on page 29,

•

activities of our Global Commodities operation in the Merchant Energy Business section of Management's Discussion and Analysis beginning on page 45,

•

evaluation of commodity and credit risk in the Market Risk section of Management's Discussion and Analysis beginning on page 64, and

•

changes to our business environment in the Business Environment section of Management's Discussion and Analysis on page 37.

Items 4 and 4(T). Controls and Procedures

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

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

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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

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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 27.

Item 1A. Risk Factors

You should consider carefully the following risks, along with the risks described under Item 1A. Risk Factors in our 2007 Annual Report on Form 10-K and the other information contained in this Form 10-Q. The risks and uncertainties described below and in our 2007 Annual Report on Form 10-K are not the only ones that may affect us. There may be additional risks and uncertainties that are not presently known or that are not currently believed to be material that may in the future adversely affect our business and operations. If any of the following events occur, our business and financial results could be materially adversely affected.

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

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

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

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

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

Changes in the prices of commodities and initial margin requirements impact our liquidity requirements.

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

Economic conditions and instability in the financial markets could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption and an increase in customers' inability to pay their accounts, which may adversely affect our financial results and future growth.

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        Instability in the financial markets, as a result of recession or otherwise, may affect the cost of capital and our ability to raise capital. We rely on the capital markets, as well as the banking and commercial paper markets, to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use letters of credit issued under our credit facilities to support our operations. Disruptions in the capital and credit markets as a result of uncertainty, reduced alternatives or failures of significant financial institutions could adversely affect our access to liquidity needed for our businesses, including our ability to close on a new credit facility of approximately $1.2 billion and complete other alternatives we are exploring. In addition, such disruptions could adversely affect our ability to draw on our credit facilities. Our access to funds under those credit facilities is dependent on the ability of the banks that are parties to the facilities to meet their funding commitments. Those banks may not be able to meet their funding commitments to us if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from borrowers within a short period of time. The disruptions in capital and credit markets may also result in higher interest rates on publicly issued debt securities and increased costs associated with commercial paper borrowing and under bank credit facilities. Any disruptions could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures, further changing our strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash. The inability to obtain the liquidity needed to meet our business requirements, or to obtain such liquidity on terms that are favorable to us, would have a material adverse effect on our business, results of operations and financial condition.

We may be unable to execute our strategies to improve liquidity and reduce invested capital.

We are actively assessing the ongoing capital requirements of our merchant energy business. We have begun the process of pursuing the sale of our upstream gas properties, international business, and gas trading operations. We cannot provide any assurance that such sales will be completed. In addition, we are undertaking other strategic initiatives to improve our liquidity, which include reducing capital spending and ongoing expenses, scaling down the expected variability in long-term earnings and short-term collateral usage, and limiting our exposure to business activities that require contingent capital support. Further, we have entered into an agreement with MidAmerican Energy Holdings Company (MidAmerican), which we expect to become effective by November 14, 2008, provided that MidAmerican has approved certain disclosure schedules that provide us the option to sell our equity interest in Safe Harbor Water Power Corporation and our West Valley generating plant to MidAmerican for aggregate proceeds of $350 million. If we cannot complete these sales or execute on our initiatives successfully, our liquidity will be adversely affected, which would have a material adverse effect on our business, results of operations and financial condition.

Our merger with MidAmerican is subject to closing conditions, including shareholder approval, that, if not satisfied or waived, will result in the merger not being completed, which may result in material adverse consequences to our business and operations, including a potential bankruptcy filing.

On September 19, 2008, we announced the execution of a merger agreement with MidAmerican. The merger is subject to closing conditions, including the approval of our shareholders that, if not satisfied, will prevent the merger from becoming effective. The closing condition that our shareholders approve the merger may not be waived under applicable law and must be satisfied for the merger to be completed. Immediately prior to executing the merger agreement with MidAmerican, we were facing severe liquidity concerns and the possibility of seeking bankruptcy protection. If our shareholders do not approve the merger and the merger does not become effective, we may be unable to continue to operate our business on a stand-alone basis and could reasonably be expected to be required to seek bankruptcy protection, unless we are able to quickly obtain alternative sources of additional liquidity in amounts and in time to prevent any adverse action by rating agencies or other adverse reactions by trading counterparties and other business partners.

The merger with MidAmerican is subject to receipt of consent or approval from governmental entities that could delay or prevent the completion of the merger, impose conditions that could cause abandonment of the merger or impose conditions that could have a material adverse effect on our future operations even if the merger is not completed.

The completion of the merger is conditioned upon the receipt of consents, orders, approvals or clearances from various federal, state and international regulatory agencies. As part of the regulatory approval process, governmental entities may impose terms and conditions that may not be acceptable to MidAmerican, which may give MidAmerican the right to terminate the merger agreement. Also, governmental entities may impose terms and conditions that are unfavorable or add

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significant additional costs to our future operations even if the merger is not completed. A substantial delay in obtaining required approvals or the imposition of unfavorable terms or conditions in connection with such approvals could have a material adverse effect on our business or financial results and could also have a negative impact on our credit ratings. In addition, delays or unfavorable terms could lead us to become involved in litigation with one or more governmental entities or private litigants or may cause MidAmerican to terminate the merger agreement and abandon the merger.

If the merger agreement with MidAmerican is terminated other than due to a breach by MidAmerican, holders of our common stock will be diluted significantly and we will incur substantial additional indebtedness.

If the merger agreement with MidAmerican is terminated other than due to a breach by MidAmerican, in addition to the $175 million termination fee that Constellation Energy will be required to pay to MidAmerican, the Series A Preferred Stock acquired by a wholly-owned subsidiary of MidAmerican, pursuant to a purchase agreement executed contemporaneously with the merger agreement will automatically convert into $1.0 billion in aggregate principal amount of 14% senior notes and, subject to the receipt of all required regulatory approvals, 35,506,757 shares of our common stock. To the extent MidAmerican has not received all regulatory approvals needed to hold all of the 35,506,757 shares of our common stock, we would be required to pay MidAmerican $26.50 for each share that could not be issued to MidAmerican because such regulatory approvals had not been received. In addition, the Series A Preferred Stock will, subject to the receipt of all required regulatory approvals, automatically convert into shares of our common stock and 14% senior notes on June 19, 2009 (or September 19, 2009 to the extent permitted in the merger agreement), whether or not the merger agreement is terminated on such applicable date. The issuance of shares of our common stock upon conversion of the Series A Preferred Stock will cause a significant reduction in the relative percentage ownership of our common stock of our current shareholders.

        Further, the 14% senior notes to be issued upon conversion of the Series A Preferred Stock will mature on December 31, 2009. This obligation will reduce the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business. In addition, under the terms of an existing credit facility commitment, the credit facility commitment would automatically be reduced by $1.0 billion upon conversion of the Series A Preferred Stock, ultimately reducing the amount of committed additional borrowings that would be available to Constellation Energy for its business operations. The conversion of the Series A Preferred Stock into additional indebtedness could also have a negative impact on our credit ratings.

        If we terminate the merger agreement due to a breach by MidAmerican, the Series A Preferred Stock will not convert into shares of our common stock or the 14% senior notes upon such termination, but we will be required on September 22, 2010 to redeem all, but not less than all, of the Series A Preferred Stock for an amount in cash equal to 100% of the stated value for each share of Series A Preferred Stock plus all accrued but unpaid dividends. Redemption of the Series A Preferred Stock will reduce the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and could also have a negative impact on our credit ratings.

If continued unprecedented instability in global financial and commodities markets materially and adversely affects the net economic value of our retail and/or wholesale businesses and assets or results in our senior unsecured debt being rated below investment grade, MidAmerican may seek to terminate the merger agreement and abandon the merger.

Extraordinary conditions in global financial and commodities markets, which have included unprecedented limitations on the availability of credit, have presented many businesses, including Constellation Energy, with unprecedented operating and liquidity challenges. If such conditions persist or worsen, and if, as a result, we face more stringent limits on our access to liquidity, further downgrades in our debt ratings (to a level below investment grade) or other unprecedented market conditions that adversely affect our business or the net value of our assets, MidAmerican may seek to terminate the merger agreement and abandon the merger. The merger agreement provides that MidAmerican is not obligated to consummate the transaction contemplated by the merger agreement if the net economic value of our retail and/or wholesale businesses or assets declines by more than $400 million between June 30, 2008 and the closing of the merger, as determined in the sole discretion of MidAmerican. In addition, MidAmerican's obligation to close the merger is conditioned upon, among other things, our senior unsecured debt having an investment grade rating with no less than a stable outlook at the time of closing.

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The voting rights and conversion features of MidAmerican's $1 billion Series A Preferred Stock investment in Constellation Energy, along with MidAmerican's right to designate one nominee to serve as a member of our board of directors, may provide MidAmerican with influence over certain corporate matters and may impact the likelihood that a third party would seek to acquire, or succeed in acquiring, Constellation Energy.

Under the articles supplementary relating to our Series A Preferred Stock, and an investor rights agreement between Constellation Energy and MidAmerican, the number of members of our board of directors was initially increased by one, and MidAmerican has the right to nominate one individual to the new directorship so long as MidAmerican and its affiliates beneficially own at least 33.3% of the shares of Series A Preferred Stock that were originally issued to a wholly-owned subsidiary of MidAmerican. If MidAmerican does not exercise its right to nominate one individual to the new directorship, it may appoint a board observer who has the right to attend and participate in all meetings of, and receive all material distributed to, our board of directors (subject to customary exceptions), but will not be entitled to vote at meetings of the board of directors or any committees thereof. MidAmerican has not exercised its right to nominate a director or appoint a board observer.

        The Series A Preferred Stock generally does not have voting rights, but the consent of the holders of such stock is required for specified matters in accordance with the terms of the articles supplementary. However, the holders of Series A Preferred Stock do not have the right to vote with respect to the merger. In addition, upon the occurrence of a conversion event of the Series A Preferred Stock, the Series A Preferred Stock, subject to the receipt of required regulatory approvals, will convert into 35,506,757 shares of our common stock (representing approximately 19.9% of the outstanding shares of our common stock on September 22, 2008, or approximately 16.6% on an as-converted basis), subject to certain adjustments, and $1 billion in aggregate principal amount of 14% senior notes.

        Moreover, following such a conversion, MidAmerican would continue to have the director nomination and related rights described above so long as MidAmerican and its affiliates beneficially own at least 50% of the shares of Constellation Energy common stock received by MidAmerican and its affiliates upon conversion of the Series A Preferred Stock. Accordingly, if the merger is terminated other than due to a breach by MidAmerican, MidAmerican's common stock ownership and director nomination rights will enable it to exert significant influence over the outcome of a range of corporate matters, including significant corporate transactions requiring a shareholder vote, such as a merger or a sale of Constellation Energy or its assets. In that circumstance, this combination of significant ownership and influence in board decision-making also could negatively affect the price of our common stock by, among other things, discouraging a potential acquirer from seeking to acquire shares of our common stock (whether by making a tender offer or otherwise) or otherwise attempting to obtain control of Constellation Energy. In addition, we will be subject to certain negative covenants relating to limitations on: amending or revising our organizational documents, liquidation, incurring indebtedness and entering into affiliate transactions.

If the merger agreement with MidAmerican is terminated and the 14% senior notes are issued by us upon conversion of the Series A Preferred Stock, the 14% senior notes will contain restrictions on the operation of our business.

The 14% senior notes to be issued upon conversion of our Series A Preferred Stock contain various covenants that will limit our ability to engage in specific types of transactions and in operating our business. We will be subject to certain affirmative covenants relating to the payment of our obligations, the conduct of our business and corporate existence, maintenance of our property and insurance and the inspection of our books and records. In addition, Constellation Energy and its subsidiaries will be subject to certain negative covenants relating to limitations on: indebtedness of Constellation Energy and its subsidiaries; incurring certain liens; engaging in certain fundamental changes; the sale of its assets; certain types of restricted payments; investments, loans and advances; acquisitions and transactions with affiliates; optional payments and modifications to debt instruments; and the issuance of capital stock of any subsidiary.

Constellation Energy and its directors and officers are named parties to a number of actions relating to the merger with MidAmerican and certain of these actions seek a court decision delaying or prohibiting the completion of the merger.

A number of actions are pending in Maryland state and federal courts relating to the merger with MidAmerican. These include securities class actions against Constellation Energy and its directors and officers, and class-action complaints on behalf of a putative Constellation Energy shareholder class against Constellation Energy and its directors and officers. The shareholder class actions and shareholder derivative actions allege that members of our board of directors breached their fiduciary duties to Constellation Energy in agreeing to the proposed merger. The shareholder class actions and shareholder

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derivative actions collectively seek declaratory judgment establishing the unenforceability of the merger based on the alleged breaches of duty, injunctive relief to enjoin the merger, rescission of the merger or rescissory damages, the imposition of a constructive trust in favor of shareholders of any benefits received by the individual members of our board of directors, and reasonable costs and expenses, including attorney's fees. Depending upon the outcome, these actions could result in a court preventing the merger, or could otherwise impede the closing of the merger and could have an adverse effect on our business and financial results.

We are subject to business uncertainties and contractual restrictions while the merger with MidAmerican is pending, as well as additional non-operating demands on management, that could adversely affect our businesses and financial results.

Uncertainty about the effect of the merger with MidAmerican on employees and customers may have an adverse effect on us, regardless of whether the merger is eventually completed. These uncertainties may impair our ability to attract, retain and motivate key personnel until the merger is completed, or the merger agreement is terminated, and for a period of time thereafter. These uncertainties also could cause customers, suppliers and others that deal with us to seek to terminate or change existing business relationships with us.

        Employee retention and recruitment may be particularly challenging during the pendency of the merger because employees and prospective employees may be uncertain about their future roles with us if the merger is completed. The departure of existing key employees or the failure of potential key employees to continue employment with us, despite our retention and recruiting efforts, could have a material adverse impact on our business, financial condition and operating results, regardless of whether the merger is eventually completed.

        The pursuit of the merger with MidAmerican places a significant burden on management and internal resources. The diversion of management attention away from day-to-day business concerns and any difficulties encountered in the transition and integration process could have a material adverse impact on our business, financial condition and operating results, regardless of whether the merger is eventually completed.

        In addition, the merger agreement restricts us, without MidAmerican's consent, from making certain acquisitions and taking other specified actions until the merger occurs or the merger agreement terminates. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to their businesses prior to completion of the merger or termination of the merger agreement.

We have agreed to limit our remedies against MidAmerican for breach of the merger agreement.

We agreed in the merger agreement that the maximum aggregate liability of MidAmerican for losses or damages in connection with the merger agreement (including the failure to complete the merger agreement once all of the conditions to the completion of the merger have been satisfied) would be limited in amount to $1 billion. Our recourse for such losses or damages is limited to the Series A Preferred Stock (or shares of our common stock and 14% senior notes issued upon conversion thereof) or the proceeds of the redemption or repayment of the Series A Preferred Stock or the 14% senior notes. The merger agreement also provides that we will not be entitled to an injunction to prevent breaches of the merger agreement by MidAmerican or to enforce specifically the terms and provisions of the merger agreement against MidAmerican. Breach of the merger agreement by MidAmerican may result in a material adverse effect on Constellation Energy for which it is not able to recover damages, which itself could have material adverse effects on Constellation Energy. In addition, if we attempt to challenge the validity of the $1 billion damage cap, such amount is automatically reduced to $1,000.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds; Issuer Purchases of Equity Securities

The sale and issuance of Constellation Energy's 8% Series A Convertible Preferred Stock to MidAmerican Energy Holdings Company was reported previously on a Current Report on Form 8-K dated September 22, 2008. We also discuss the issuance in the Notes to Consolidated Financial Statements beginning on page 21.

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

Period	Total Number of Shares Purchased1		Average Price Paid for Shares		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Dollar Amounts of Shares that May Yet Be Purchased Under the Plans and Programs (at month end)2
July 1 – July 31, 2008		200,030	$	80.79		—	$	750 million
August 1 – August 31, 2008		77		65.54		—		750 million
September 1 – September 30, 2008		—		—		—		750 million
Total		200,107	$	80.79		—		—

1 Represents shares surrendered by employees to satisfy tax withholding obligations on vested restricted stock and shares repurchased in the open market to satisfy employee stock option exercises and restricted stock grants.

2 In October 2007, our board of directors approved a common share repurchase program for up to $1 billion of our outstanding common shares over a 24 month period following approval. Pursuant to our merger agreement with MidAmerican Energy Holdings Company (MidAmerican), we are prohibited from repurchasing additional shares of our common stock without MidAmerican's prior consent. We do not intend to make further repurchases under this program.

Item 4. Submission of Matters to Vote of Security Holders

On July 18, 2008, we held our annual meeting of shareholders. At that meeting, the following matters were voted upon:

1.

Directors nominated by Constellation Energy were elected to serve for a term to expire in 2009 and until their successors are duly elected and qualified as follows:

	COMMON SHARES CAST:
	For		Against		Abstain
Yves C. de Balmann		145,485,663		1,014,636		1,720,410
Douglas L. Becker		113,400,484		33,019,637		1,800,592
Ann C. Berzin		145,375,252		1,114,058		1,731,395
James T. Brady		144,500,244		1,947,799		1,772,662
Edward A. Crooke		145,270,488		1,146,429		1,803,788
James R. Curtiss		137,328,844		9,092,485		1,799,378
Freeman A. Hrabowski III		145,229,547		1,176,185		1,814,978
Nancy Lampton		143,937,856		2,502,111		1,780,742
Robert J. Lawless		137,568,438		8,913,781		1,738,490
Lynn M. Martin		144,252,737		2,167,950		1,800,024
Mayo A. Shattuck III		140,884,971		5,518,929		1,816,814
John L. Skolds		145,540,996		898,575		1,781,137
Michael D. Sullivan		145,000,035		1,398,771		1,821,902

2.

The ratification of PricewaterhouseCoopers LLP as independent registered public accounting firm for 2008 was approved. With respect to holders of common stock, the number of affirmative votes cast was 141,364,031, the number of votes cast against was 5,191,709, and the number of abstentions was 1,664,973.

3.

The amendment to our charter to increase the number of authorized shares of common stock was approved. With respect to holders of common stock, the number of affirmative votes cast was 106,595,658, the number of votes cast against was 39,641,342, and the number of abstentions was 1,983,707.

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Item 5. Other Information

Forward Looking Statements

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

•

the timing and extent of changes in commodity prices and volatilities for energy and energy related products including coal, natural gas, oil, electricity, nuclear fuel, freight, and emission allowances, and the impact of such changes on our liquidity requirements,

•

the liquidity and competitiveness of wholesale markets for energy commodities,

•

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

•

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

•

the timing and extent of deregulation of, and competition in, the energy markets, and the rules and regulations adopted in those markets,

•

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

•

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

•

the ability of our regulated and nonregulated businesses to comply with complex and/or changing market rules and regulations,

•

the ability of BGE to recover all its costs associated with providing customers service,

•

the conditions of the capital markets, interest rates, foreign exchange rates, availability of credit facilities to support business requirements, liquidity, and general economic conditions, as well as Constellation Energy and BGE's ability to maintain their current credit ratings,

•

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

•

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

•

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

•

changes in accounting principles or practices,

•

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

•

the ability to successfully identify and complete acquisitions and sales of businesses and assets,

•

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

•

the likelihood and timing of the completion of the pending merger with MidAmerican Energy Holdings Company, the terms and conditions of any required regulatory approvals for the pending merger, potential impact of a termination of the merger and potential diversion of management's time, and attention from our ongoing business during this time period, and

•

the ability to complete our strategic initiatives to improve our liquidity.

        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

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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.

Amendments to Benefit Plans and Agreements

On October 16, 2008, the Compensation Committee of the Board of Directors of Constellation Energy approved amendments to the benefit plans and agreements set forth below to ensure an exemption from or compliance with Section 409A of the Internal Revenue Code of 1986, as amended (Code). Section 409A governs nonqualified deferred compensation arrangements and imposes an additional tax and penalties if a nonqualified deferred compensation arrangement does not comply with Section 409A.

•

Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan

•

Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors

•

Constellation Energy Group, Inc. Benefits Restoration Plan

•

Constellation Energy Group, Inc. Supplemental Pension Plan

•

Constellation Energy Group, Inc. Senior Executive Supplemental Plan

•

Change in Control Severance Agreements with certain executive officers

        None of the changes made to the benefit plans and agreements enhanced the amount of benefits to which a participant is or may be entitled under the benefit plans and agreements.

        In addition, the Compensation Committee approved an amendment to Constellation Energy's 2007 Executive Annual Incentive Plan (AIP) to reflect recent interpretative guidance provided by the Internal Revenue Service regarding when payments made upon an involuntary termination without cause are deemed performance-based for purposes of Section 162(m) of the Code. The AIP has been amended to delay payouts to participants who are terminated at the request of a third party who has taken steps reasonably calculated to effect a change in control or in anticipation of a change in control transaction until the earlier of the end of the applicable performance period or the completion of the change in control transaction.

        The amended and restated AIP has been filed as an exhibit to this Form 10-Q. The other amended and restated plans and agreements referenced above will be filed as exhibits to our 2008 Form 10-K.

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Item 6. Exhibits

Exhibit No. 2(a)	*	Agreement and Plan of Merger, dated as of September 19, 2008, by and among Constellation Energy Group, Inc., MidAmerican Energy Holdings Company and MEHC Merger Sub, Inc. (Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated September 19, 2008, File No. 1-12869).
Exhibit No. 3(a)	*	Articles Supplementary of Constellation Energy Group, Inc., dated as of September 19, 2008 (Designated as Exhibit No. 3.1 to the Current Report on Form 8-K dated September 19, 2008, File No. 1-12869).
Exhibit No. 10(a)	*	Stock Purchase Agreement, dated as of September 19, 2008, by and between Constellation Energy Group, Inc. and MidAmerican Energy Holdings Company (Designated as Exhibit 10.1 to the Current Report on Form 8-K dated September 19, 2008, File No. 1-12869).
Exhibit No. 10(b)	*	Form of Promissory Note to be issued to MidAmerican Energy Holdings Company (Designated as Exhibit 10.2 to the Current Report on Form 8-K dated September 19, 2008, File No. 1-12869).
Exhibit No. 10(c)	*	Investor Rights Agreement, dated as of September 19, 2008, by and between Constellation Energy Group, Inc. and MidAmerican Energy Holdings Company (Designated as Exhibit 10.3 to the Current Report on Form 8-K dated September 19, 2008, File No. 1-12869).
Exhibit No. 10(d)		Executive Annual Incentive Plan of Constellation Energy Group, Inc. as amended and restated.
Exhibit No. 10(e)	*	Letter agreement of Mayo A. Shattuck III dated October 16, 2008 (Designated as Exhibit 10.1 to the Current Report on Form 8-K dated October 21, 2008, File No. 1-12869).
Exhibit No. 10(f)	*	Letter agreement of Thomas V. Brooks dated October 17, 2008 (Designated as Exhibit 10.2 to the Current Report on Form 8-K dated October 21, 2008, File No. 1-12869).
Exhibit No. 10(g)	*	Letter agreement of John R. Collins dated October 17, 2008 (Designated as Exhibit 10.3 to the Current Report on Form 8-K dated October 21, 2008, File No. 1-12869).
Exhibit No. 12(a)		Constellation Energy Group, Inc. Computation of Ratio of Earnings to Fixed Charges.
Exhibit No. 12(b)		Baltimore Gas and Electric Company Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.
Exhibit No. 31(a)		Certification of Chairman of the Board, President, and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 31(b)		Certification of Executive Vice President and Chief Financial Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 31(c)		Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 31(d)		Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(a)		Certification of Chairman of the Board, President, and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(b)		Certification of Executive Vice President and Chief Financial Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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Exhibit No. 32(c)	Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(d)	Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*

Incorporated by reference

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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 10, 2008	/s/ JONATHAN W. THAYER Jonathan W. Thayer, Senior 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

TABLE OF CONTENTS
PART 1—FINANCIAL INFORMATION
Item 1—Financial Statements
CONSOLIDATED STATEMENTS OF INCOME (LOSS) (UNAUDITED)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
CONSOLIDATED STATEMENTS OF INCOME (LOSS) (UNAUDITED)
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Item 2. Management's Discussion
Introduction and Overview
Strategy
Business Environment
Current Market Developments
Commodity Prices
Merger and Strategic Alternatives Costs
Workforce Reduction Costs
Emission Allowances
Asset Sales
Financing Activities
Maryland Settlement Agreement
Results of Operations for the Quarter and Nine Months Ended September 30, 2008 Compared with the Same Periods of 2007
Financial Condition
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Items 4 and 4(T). Controls and Procedures
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds; Issuer Purchases of Equity Securities
Item 4. Submission of Matters to Vote of Security Holders
Item 5. Other Information
Item 6. Exhibits
SIGNATURE

EX-10.(D)

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Exhibit 10(d)

Constellation Energy Group, Inc.
Executive Annual Incentive Plan
(Plan)
Amended and restated 2007
Amended October 16, 2008, effective January 1, 2009

1.

Purpose.    The purpose of the Plan is to permit the Company, through awards of annual incentive compensation qualifying for federal income tax deductions, to attract and retain executives and to motivate these executives to promote the profitability and growth of the Company.

2.

Definitions.    All singular terms defined in this Plan will include the plural and vice versa. As used herein, the following terms will have the meaning specified below:

"Award" means the amount granted to a Participant by the Committee for a Performance Period under the Plan, whether paid in cash, stock, restricted stock, stock options, other stock-based or stock- denominated units or any other form of consideration.

"Board" means the Board of Directors of the Company.

"Change in Control" means the occurrence of any one of the following events:

        (i)    individuals who, on the effective date of the adoption of the Plan, constitute the Board (the "Incumbent Directors") cease for any reason to constitute at least a majority of the Board, provided that any person becoming a director subsequent to such adoption date, whose election or nomination for election was approved by a vote of at least two-thirds of the Incumbent Directors then on the Board (either by a specific vote or by approval of the proxy statement of the Company in which such person is named as a nominee for director, without written objection to such nomination) shall be an Incumbent Director; provided, however, that no individual initially elected or nominated as a director of the Company as a result of an actual or threatened election contest with respect to directors or as a result of any other actual or threatened solicitation of proxies by or on behalf of any person other than the Board shall be deemed to be an Incumbent Director;

        (ii)   any "person" (as such term is defined in Section 3(a)(9) of the Securities Exchange Act of 1934, as amended (the "Exchange Act") and as used in Sections 13(d)(3) and 14(d)(2) of the Exchange Act) is or becomes a "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Company representing 20% or more of the combined voting power of the Company's then outstanding securities eligible to vote for the election of the Board (the "Company Voting Securities"); provided, however, that the event described in this paragraph (ii) shall not be deemed to be a change in control by virtue of any of the following acquisitions: (A) by the Company or any corporation with respect to which the Company owns a majority of the outstanding shares of common stock or has the power to vote or direct the voting of sufficient securities to elect a majority of the directors (a "Subsidiary Company"),

(B) by any employee benefit plan (or related trust) sponsored or maintained by the Company or any Subsidiary Company, (C) by any underwriter temporarily holding securities pursuant to an offering of such securities, (D) pursuant to a Non-Qualifying Transaction (as defined in paragraph (iii)), or (E) pursuant to any acquisition by a Participant or any group of persons including a Participant (or any entity controlled by a Participant or any group of persons including a Participant);

        (iii)  consummation of a merger, consolidation, statutory share exchange or similar form of corporate transaction involving the Company (a "Business Combination"), unless immediately following such Business Combination: (A) more than 60% of the total voting power of (x) the corporation resulting from such Business Combination (the "Surviving Corporation"), or (y) if applicable, the ultimate parent corporation that directly or indirectly has beneficial ownership of at least 95% of the voting securities eligible to elect directors of the Surviving Corporation (the "Parent Corporation"), is represented by Company Voting Securities that were outstanding immediately prior to such Business Combination (or, if applicable, is represented by shares into which such Company Voting Securities were converted pursuant to such Business Combination), and such voting power among the holders thereof is in substantially the same proportion as the voting power of such Company Voting Securities among the holders thereof immediately prior to the Business Combination, (B) no person (other than any employee benefit plan (or related trust) sponsored or maintained by the Surviving Corporation or the Parent Corporation), is or becomes the beneficial owner, directly or indirectly, of 20% or more of the total voting power of the outstanding voting securities eligible to elect directors of the Parent Corporation (or, if there is no Parent Corporation, the Surviving Corporation) and (C) at least a majority of the members of the board of directors of the Parent Corporation (or, if there is no Parent Corporation, the Surviving Corporation) following the consummation of the Business Combination were Incumbent Directors at the time of the Board's approval of the execution of the initial agreement providing for such Business Combination (any Business Combination which satisfies all of the criteria specified in (A), (B), and (C) above shall be deemed to be a "Non-Qualifying Transaction"); or

        (iv)  the stockholders of the Company approve a plan of complete liquidation or dissolution of the Company, or the consummation of a sale of all or substantially all of the Company's assets.

Notwithstanding the foregoing, a change in control of the Company shall not be deemed to occur solely because any person acquires beneficial ownership of more than 20% of the Company Voting Securities as a result of the acquisition of Company Voting Securities by the Company which reduces the number of Company Voting Securities outstanding; provided, that if after such acquisition by the Company such person becomes the beneficial owner of additional Company Voting Securities that increases the percentage of outstanding Company Voting Securities beneficially owned by such person, a change in control of the Company shall then occur.

2

"Code" means the Internal Revenue Code of 1986, as amended. Reference in the Plan to any section of the Code will be deemed to include any amendments or successor provisions to such section and any regulations promulgated thereunder.

"Committee" means the Compensation Committee of the Board or such other committee as the Board shall appoint from time to time to administer the Plan and to otherwise exercise and perform the authority and functions assigned to the Committee under the terms of the Plan, at least two members of which qualify as non-employee directors (within the meaning of Rule 16b-3 promulgated under Section 16 of the 1934 Act), and as "outside directors" within the meaning of Treasury Regulation Section 1.162-27(e)(3) and as "independent" within the meaning of any rules or regulations promulgated by an applicable stock exchange or similar regulatory authority rules and regulations.

"Company" means Constellation Energy Group, Inc., a Maryland corporation, or its successor, including any "New Company" as provided in Section 10G.

"Deferred Compensation Plan" means the Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan or any successor or future similar plans.

"Executive" means any executive officer of the Company as defined in Section 16 of the 1934 Act.

"Extraordinary Items" means extraordinary, unusual, and nonrecurring items of gain or loss as defined under U.S. generally accepted accounting principles and as reported in the Company's annual report to shareholders or as otherwise reported to shareholders.

"Income from Continuing Operations Before Income Taxes" means the consolidated income before income taxes and excluding (i) discontinued operations; (ii) Extraordinary Items; and, (iii) cumulative effect of change in accounting principle; if applicable, for the Performance Period, computed in accordance with U.S. generally accepted accounting principles and as reported in the Company's annual report to shareholders or as otherwise reported to shareholders.

"Income from Operations" means the consolidated income before income taxes and excluding: (i) discontinued operations; (ii) Extraordinary Items; (iii) cumulative effect of change in accounting principle; (iv) fixed charges; and (v) other non-operating income and expenses; if applicable, for the Performance Period, computed in accordance with U.S. generally accepted accounting principles and as reported in the Company's annual report to shareholders or as otherwise reported to shareholders.

"1934 Act" means the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.

"Net Income" means the consolidated net income for the Performance Period, computed in accordance with U.S. generally accepted accounting principles and

3

as reported in the Company's annual report to shareholders or as otherwise reported to shareholders.

"Net Cash Provided by Operating Activities" means net cash flow from operating activities computed in accordance with U.S. generally accepted accounting principles and as reported in the Company's annual report to shareholders or as otherwise reported to shareholders.

"Participant" means an individual who has been granted a conditional opportunity to earn an Award under the Plan.

"Performance Period" means the taxable year of the Company or any other period designated by the Committee with respect to which an Award may be granted.

"Stock Plans" means the Constellation Energy Group, Inc. 2007 Long-Term Incentive Plan and/or any successor or predecessor stock plans adopted or assumed by the Company.

"Subsidiary" means any entity that is directly or indirectly controlled by the Company or any entity, including an acquired entity, in which the Company has a significant equity interest, as determined by the Committee, in its discretion.

"Year" means a fiscal year of the Company that constitutes all or part of the applicable Performance Period.

3.

Administration.    The Committee is the Plan Administrator and has sole authority (except as specified otherwise herein) to determine all questions of interpretation and application of the Plan, or of the terms and conditions pursuant to which Awards are granted under the Plan provisions, and, in general, to make all determinations advisable for the administration of the Plan to achieve its stated purpose. The Plan Administrator's determinations under the Plan (including without limitation, determinations of the persons to receive Awards, the form, amount and timing of such Awards, the terms and provisions of such Awards and any agreements evidencing such Awards) need not be uniform and may be made by the Plan Administrator selectively among persons who receive, or are eligible to receive, Awards under the Plan, whether or not such persons are similarly situated. Such determinations shall be final and not subject to further appeal.

4.

Eligibility.    For a Performance Period, each Executive may be designated by the Committee as a Participant.

5.

Awards.

A.

Provision for Awards.    Each Participant may receive an Award in any Performance Period based on upon a percentage of an incentive pool equal to the greater of (i) 3% of the Company's Income from Operations; (ii) 3% of the Company's Income from Continuing Operations Before Income Taxes; (iii) 5% of the Company's Net Income for the Performance Period, and (iv) 20% of the Company's Net Cash Provided by Operating Activities for the Performance

4

Period (as each term is defined in the Plan). At the beginning of the Performance Period, the Committee will allocate an incentive pool percentage to each participating employee for each Performance Period; provided that in any Performance Period the incentive pool percentage for any one participant may not exceed 50% of the total pool and the sum of the incentive pool percentages for all participants cannot exceed 100% of the total pool. As soon as practicable following the determination of the incentive pool for a Performance Period, the Committee will calculate each participant's portion of the incentive pool based upon the percentage established at the beginning of the Performance Period.

B.

Committee Discretion to Determine Award.    The Committee has the sole discretion to determine the standard or formula pursuant to which each Participant's Award shall be calculated, whether all or any portion of the amount so calculated will be paid, and the specific amount (if any) to be paid to each Participant, subject in all cases to the terms, conditions and limits of the Plan. To this same extent, the Committee may at any time establish (and, once established, rescind, waive or amend) additional conditions and terms of payment of Awards (including but not limited to the achievement of other financial, strategic or individual goals, which may be objective or subjective) as it may deem desirable in carrying out the purposes of the Plan. The Committee has discretion to adjust all such Awards downwards, but in no event may the portion of the incentive pool allocated to a Participant be increased in any way, including as a result of the reduction of any other Participant's allocated portion.

6.

Payment of Awards.    Each Participant shall be eligible to receive, within a reasonable period of time, as determined in the sole discretion of the Committee, after the amount of such Participant's Award for a Performance Period has been determined, all or a portion of that Award. Awards may be paid in cash, stock, restricted stock, stock options, other stock-based or stock-denominated units or any other form of consideration or any combination thereof determined by the Committee. Equity or equity-based awards may be granted under the terms and conditions of the applicable Stock Plans. Payment of the Award may be deferred at the discretion of the Committee. A Participant may elect to defer the receipt of all or a portion of the Award for the Performance Year. Any such deferral and investment of any such amounts deferred pursuant to this Plan shall be made in accordance with the provisions of the Deferred Compensation Plan. No provision of this paragraph shall be given effect to the extent such provision would cause any tax to become due under Section 409A of the Code.

7.

Designation of Beneficiary.    A Participant shall have the right to designate a beneficiary or beneficiaries who are to receive in a lump sum any undistributed Award to the extent a Participant has chosen not to defer all or a portion of the Award pursuant to Section 7 hereof, should the Participant die during the Performance Period and be entitled to an incentive award for that Performance Period. Such designation shall apply only to the portion of the undistributed Award not subject to a deferral election. Any designation, change or rescission of the designation shall be made in writing by completing and furnishing to the Senior Vice President—Human Resources of the Company or successor to such position a notice on an appropriate form designated by such Senior Vice President. The last designation of beneficiary received by the Senior Vice President—Human Resources of the Company or successor to such position

5

shall be controlling over any testamentary or purported disposition by the Participant, provided that no designation, rescission or change thereof shall be effective unless received prior to the death of the Participant. Distribution of any Awards previously deferred pursuant to Section 7 of the Plan shall be paid to the beneficiary or beneficiaries designated under the Deferred Compensation Plan.

8.

Change in Control.    Notwithstanding any other provisions of this Plan to the contrary, if a Participant separates from service with the Company or a Subsidiary (except due to a Participant's transfer of employment to or from a Subsidiary), within 2 years following a Change in Control, such Participant is eligible for an Award for the Performance Period during which the separation from service occurs. The Award is calculated assuming maximum performance achievement, prorated for service during the Performance Period, and based on the Participant's position at the time of termination. Payment of the Award will be made within 60 days after the Participant's separation from service. Payment may not be deferred.

If a Participant's employment with the Company or a Subsidiary is terminated prior to a Change in Control, and it is reasonably demonstrated that such termination (a) was at the request of a third party who has taken steps reasonably calculated to effect a Change in Control or (b) otherwise arose in connection with or anticipation of a Change in Control, such Participant is eligible for an Award for the Performance Period during which the separation from service occurs. The Award shall be paid upon the earliest to occur of either the end of the Performance Period or the Change in Control. If the Performance Period ends before the Change in Control occurs, then the Award is calculated based on actual performance, prorated for service during the Performance Period, and based on the Participant's position at the time of termination. If the Award is paid upon the Change in Control, then it shall be calculated assuming maximum performance achievement, prorated for service during the Performance Period, and based on the Participant's position at the time of termination. Payment may not be deferred.

Notwithstanding any provision in the Plan to the contrary, on or within 2 years after a Change in Control, no action, including, but not by way of limitation, the amendment, suspension or termination of the Plan, shall be taken which would materially adversely affect the rights of any Participant without such Participant's prior written consent.

9.

Amendment of Plan.    The Committee may at any time and from time to time alter, amend, suspend or terminate the Plan in whole or in part, except (i) no such action may be taken without the consent of the Participant to whom any Award was previously earned, which materially adversely affects the rights of such Participant concerning such Award, except as such termination or amendment of the Plan is required by statute, or rules and regulations promulgated thereunder and (ii) no such action that would require the consent of the Board and/or stockholders of the Company pursuant to Section 162(m) of the Code or the 1934 Act, or any other applicable law, rule or regulation, shall be effective without such consent. Notwithstanding the foregoing, except as otherwise required by applicable law, rule or regulation, the Committee may amend the Plan as desirable at the discretion of Committee to address any

6

issues concerning (i) Section 162(m) of the Code or (ii) maintaining an exemption under rule 16b-3 of the 1934 Act. No provision of this Section 10 shall be given effect to the extent that such provision would cause any tax to become due under Section 409A of the Code.

10.

Miscellaneous Provisions.

        A.    Nontransferability.    No benefit provided under the Plan shall be subject to alienation or assignment by a Participant (or by any person entitled to such benefit pursuant to the terms of this Plan), nor shall it be subject to attachment or other legal process except (i) to the extent specifically mandated and directed by applicable state or federal statute; (ii) as requested by the Participant (or by any person entitled to such benefit pursuant to the terms of the Plan), and approved by the Committee, to satisfy income tax withholding; and (iii) as requested by the Participant and approved by the Committee, to members of the Participant's family, or a trust established by the Participant for the benefit of family members.

        B.    No Employment Right.    Participation in this Plan shall not constitute a contract of employment between the Company or any Subsidiary and any person and shall not be deemed to be consideration for, or a condition of, continued employment of any person.

        C.    Tax Withholding.    The Company or a Subsidiary may withhold any applicable federal, state or local taxes at such time and upon such terms and conditions as required by law or determined by the Company or a Subsidiary.

        D.    Compliance with Section 409A of the Code.    This Plan is intended to comply and shall be administered in a manner that is intended to comply with section 409A of the Code and shall be construed and interpreted in accordance with such intent. To the extent that an Award and/or payment is subject to section 409A of the Code, it shall be awarded and/or paid in a manner that will comply with section 409A of the Code, including proposed, temporary or final regulations or any other guidance issued by the Secretary of the Treasury and the Internal Revenue Service with respect thereto. Any provision of this Plan that would cause an Award and/or payment to fail to satisfy section 409A of the Code shall have no force and effect until amended to comply with Code section 409A (which amendment may be retroactive to the extent permitted by applicable law).

        E.    Indemnification.    Each person who is or at any time serves as a member of the Committee (and each person or committee to whom the Committee or any member thereof has delegated any of its authority or power under this Plan) shall be indemnified and held harmless by the Company against and from (i) any loss, cost, liability, or expense that may be imposed upon or reasonably incurred by such person in connection with or resulting from any claim, action, suit, or proceeding to which such person may be a party or in which such person may be involved by reason of any action or failure to act under the Plan; and (ii) any and all amounts paid by such person in satisfaction of judgment in any such action, suit, or proceeding relating to the Plan. Each person covered by this indemnification shall give the Company an opportunity, at its own expense, to handle and defend the same before such person undertakes to handle and defend it on such person's own behalf. The foregoing right of indemnification

7

shall not be exclusive of any other rights of indemnification to which such persons may be entitled under the Charter or By-Laws of the Company or any of its Subsidiaries, as a matter of law, or otherwise, or any power that the Company may have to indemnify such person or hold such person harmless.

        F.     Reliance on Reports.    Each member of the Committee (and each person or committee to whom the Committee or any member thereof has delegated any of its authority or power under this Plan) shall be fully justified in relying or acting in good faith upon any report made by the independent registered accounting firm of the Company and its Subsidiaries and upon any other information furnished in connection with the Plan. In no event shall any person who is or shall have been a member of the Committee be liable for any determination made or other action taken or any omission to act in reliance upon any such report or information or for any action taken, including the furnishing of information, or failure to act, if in good faith.

        G.    Severability.    If any provision of this Plan would cause Awards not to constitute "other performance-based compensation" under Section 162(m) of the Code, that provision shall be severed from, and shall be deemed not to be a part of, the Plan, but the other provisions hereof shall remain in full force and effect. Any specific action by the Committee that would be violative of Section 162(m) of the Code and the regulations thereunder shall be void.

        H.    Company Successors.    In the event the Company becomes a party to a merger, consolidation, sale of substantially all of its assets or any other corporate reorganization in which the Company will not be the surviving corporation or in which the holders of the common stock of the Company will receive securities of another corporation (in any such case, the "New Company"), then the New Company shall assume the rights and obligations of the Company under this Plan.

        I.     Governing Law.    All matters relating to the Plan or to Awards granted hereunder shall be governed by the laws of the State of Maryland, without regard to the principles of conflict of laws.

        J.     Relationship to Other Benefits.    Any Awards under this Plan are not considered compensation for purposes of determining benefits under any pension, profit sharing, or other retirement or welfare plan, or for any other general employee benefit program, unless expressly considered as compensation under the terms of such plan or program.

        K.    Expenses.    The expenses of administering the Plan shall be borne by the Company and its Subsidiaries.

        L.    Titles and Headings.    The titles and headings of the sections in the Plan are for convenience of reference only, and in the event of any conflict, the text of the Plan, rather than such titles or headings, shall control.

11.

Effective Date.    The Plan shall be effective beginning on January 1, 2007, subject to approval by the stockholders of the Company in accordance with Maryland law and Section 162(m) of the Code.

8

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Exhibit 10(d)

Constellation Energy Group, Inc. Executive Annual Incentive Plan (Plan) Amended and restated 2007 Amended October 16, 2008, effective January 1, 2009

EX-12.(A)

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Exhibit 12(a)

CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

		9 Months Ended		12 Months Ended
		September 2008		December 2007		December 2006		December 2005		December 2004		December 2003
		(In millions)
Income from Continuing Operations (Before Extraordinary Loss and Cumulative Effects of Changes in Accounting Principles)		$	91.5	$	822.4	$	748.6	$	535.9	$	498.4	$	409.4
Taxes on Income, Including Tax Effect for BGE Preference Stock Dividends			64.7		419.2		343.1		155.4		110.2		213.7
Adjusted Income		$	156.2	$	1,241.6	$	1,091.7	$	691.3	$	608.6	$	623.1
Fixed Charges:
	Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness, net of amounts capitalized	$	226.6	$	292.8	$	315.9	$	297.6	$	315.9	$	325.6
	Earnings Required for BGE Preference Stock Dividends		16.6		22.3		21.1		21.6		21.4		21.7
	Capitalized Interest and Allowance for Funds Used During Construction		26.2		19.4		13.7		9.9		9.7		11.7
	Interest Factor in Rentals		68.7		96.7		4.5		6.1		4.1		3.5
	Total Fixed Charges	$	338.1	$	431.2	$	355.2	$	335.2	$	351.1	$	362.5
Amortization of Capitalized Interest		$	2.5	$	3.5	$	4.3	$	3.7	$	2.8	$	2.4
Earnings (1)		$	470.6	$	1,656.9	$	1,437.5	$	1,020.3	$	952.8	$	976.3
Ratio of Earnings to Fixed Charges			1.39		3.84		4.05		3.04		2.71		2.69

(1)

Earnings are deemed to consist of income from continuing operations (before extraordinary items, cumulative effects of changes in accounting principles, and income (loss) from discontinued operations) that includes earnings of Constellation Energy's consolidated subsidiaries, equity in the net income of unconsolidated subsidiaries, income taxes (including deferred income taxes, investment tax credit adjustments, and the tax effect of BGE's preference stock dividends), and fixed charges (including the amortization of capitalized interest but excluding the capitalization of interest).

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Exhibit 12(a)

CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

EX-12.(B)

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Exhibit 12(b)

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND
PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS

		9 Months Ended			12 Months Ended
		September 2008			December 2007		December 2006		December 2005		December 2004		December 2003
		(In millions)
(Loss) Income from Continuing Operations (Before Extraordinary Loss)		$	(4.6	)	$	139.8	$	170.3	$	189.0	$	166.3	$	163.2
Taxes on Income			(1.3	)		96.0		102.2		119.9		102.5		105.2
Adjusted (Loss) Income		$	(5.9	)	$	235.8	$	272.5	$	308.9	$	268.8	$	268.4
Fixed Charges:
	Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness, net of amounts capitalized	$	105.6		$	127.9	$	104.6	$	95.6	$	97.3	$	112.8
	Interest Factor in Rentals		0.2			0.3		0.3		0.3		0.5		0.7
	Total Fixed Charges	$	105.8		$	128.2	$	104.9	$	95.9	$	97.8	$	113.5
Preferred and Preference
	Dividend Requirements: (1)
	Preferred and Preference Dividends	$	9.9		$	13.2	$	13.2	$	13.2	$	13.2	$	13.2
	Income Tax Required		6.7			9.1		8.0		8.4		8.1		8.6
	Total Preferred and Preference Dividend Requirements	$	16.6		$	22.3	$	21.2	$	21.6	$	21.3	$	21.8
Total Fixed Charges and Preferred and Preference Dividend Requirements		$	122.4		$	150.5	$	126.1	$	117.5	$	119.1	$	135.3
Earnings (2)		$	99.9		$	364.0	$	377.4	$	404.8	$	366.6	$	381.9
Ratio of Earnings to Fixed Charges			N/A			2.84		3.60		4.22		3.75		3.36
Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements			N/A			2.42		2.99		3.45		3.08		2.82

(1)

Preferred and preference dividend requirements consist of an amount equal to the pre-tax earnings that would be required to meet dividend requirements on preferred stock and preference stock.

(2)

Earnings are deemed to consist of income from continuing operations (before extraordinary items) that includes earnings of BGE's consolidated subsidiaries, income taxes (including deferred income taxes and investment tax credit adjustments), and fixed charges other than capitalized interest.

N/A

Due to the loss for the nine months ended September 30, 2008, the ratio coverage was less than 1:1. BGE would have needed to generate additional earnings of $5.9 million to achieve a coverage of 1:1 for the ratio of earnings to fixed charges, and would have needed to generate additional earnings of $22.5 million to achieve a coverage of 1:1 for the ratio of earnings to combined fixed charges and preference dividend requirements.

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Exhibit 12(b)

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS

EX-31.(A)

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Exhibit 31(a)

CONSTELLATION ENERGY GROUP, INC.

CERTIFICATION

I, Mayo A. Shattuck III, certify that:

1.

I have reviewed this report on Form 10-Q of Constellation Energy Group, Inc.;



2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;



3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;



4.

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:



(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;



(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;



(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and



(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and



5.

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):



(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and



(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 10, 2008

/s/ MAYO A. SHATTUCK III
Chairman of the Board, President, and Chief Executive Officer

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Exhibit 31(a)

CONSTELLATION ENERGY GROUP, INC. CERTIFICATION

EX-31.(B)

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Exhibit 31(b)

CONSTELLATION ENERGY GROUP, INC.

CERTIFICATION

I, Jonathan W. Thayer, certify that:

1.

I have reviewed this report on Form 10-Q of Constellation Energy Group, Inc.;



2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;



3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;



4.

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:



(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;



(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;



(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and



(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and



5.

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):



(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and



(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 10, 2008

/s/ JONATHAN W. THAYER
Senior Vice President and Chief Financial Officer

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Exhibit 31(b)

CONSTELLATION ENERGY GROUP, INC. CERTIFICATION

EX-31.(C)

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Exhibit 31(c)

BALTIMORE GAS AND ELECTRIC COMPANY

CERTIFICATION

I, Kenneth W. DeFontes, Jr., certify that:

1.

I have reviewed this report on Form 10-Q of Baltimore Gas and Electric Company;



2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;



3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;



4.

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:



(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;



(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;



(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and



(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and



5.

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):



(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and



(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 10, 2008

/s/ KENNETH W. DEFONTES, JR.
President and Chief Executive Officer

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Exhibit 31(c)

BALTIMORE GAS AND ELECTRIC COMPANY CERTIFICATION

EX-31.(D)

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Exhibit 31(d)

BALTIMORE GAS AND ELECTRIC COMPANY

CERTIFICATION

I, Jonathan W. Thayer, certify that:

1.

I have reviewed this report on Form 10-Q of Baltimore Gas and Electric Company;



2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;



3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;



4.

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:



(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;



(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;



(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and



(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and



5.

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):



(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and



(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 10, 2008

/s/ JONATHAN W. THAYER
Senior Vice President and Chief Financial Officer

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Exhibit 31(d)

BALTIMORE GAS AND ELECTRIC COMPANY CERTIFICATION

EX-32.(A)

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Exhibit 32(a)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Mayo A. Shattuck III, Chairman of the Board, President, and Chief Executive Officer of Constellation Energy Group, Inc., certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:

        (i)    The accompanying Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and

        (ii)   The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Constellation Energy Group, Inc.

/s/ MAYO A. SHATTUCK III
Mayo A. Shattuck III
Chairman of the Board, President, and
Chief Executive Officer

Date: November 10, 2008

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Exhibit 32(a)

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

EX-32.(B)

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Exhibit 32(b)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Jonathan W. Thayer, Senior Vice President and Chief Financial Officer of Constellation Energy Group, Inc., certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:

        (i)    The accompanying Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and

        (ii)   The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Constellation Energy Group, Inc.

/s/ JONATHAN W. THAYER
Jonathan W. Thayer
Senior Vice President and Chief Financial Officer

Date: November 10, 2008

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Exhibit 32(b)

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

EX-32.(C)

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Exhibit 32(c)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Kenneth W. DeFontes, Jr., President and Chief Executive Officer of Baltimore Gas and Electric Company, certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:

        (i)    The accompanying Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and

        (ii)   The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gas and Electric Company.

/s/ KENNETH W. DEFONTES, JR.
Kenneth W. DeFontes, Jr.
President and Chief Executive Officer

Date: November 10, 2008

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Exhibit 32(c)

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

EX-32.(D)

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Exhibit 32(d)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Jonathan W. Thayer, Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company, certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:

        (i)    The accompanying Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and

        (ii)   The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gas and Electric Company.

/s/ JONATHAN W. THAYER
Jonathan W. Thayer
Senior Vice President and Chief Financial Officer

Date: November 10, 2008

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Exhibit 32(d)

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002