10-K

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

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended DECEMBER 31, 2001

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

(States of incorporation)

250 W. PRATT STREET                  BALTIMORE, MARYLAND                  21201
                                               (Address of principal executive offices)                  (Zip Code)

410-234-5000

(Registrants' telephone number, including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

Title of each class		Name of Each Exchange on Which Registered
Constellation Energy Group, Inc. Common Stock—Without Par Value	)	New York Stock Exchange, Inc. Chicago Stock Exchange, Inc. Pacific Exchange, Inc.
7.16% Trust Originated Preferred Securities ($25 liquidation amount per preferred security) issued by BGE Capital Trust I, fully and unconditionally guaranteed, based on several obligations, by Baltimore Gas and Electric Company	)	New York Stock Exchange, Inc.

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:

Not Applicable

         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 X        No     .

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    o

         Aggregate market value of Constellation Energy Group, Inc. Common Stock, without par value, held by non-affiliates as of March 22, 2002 was approximately $5,017,011,491 based upon New York Stock Exchange composite transaction closing price.

CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE 163,723,842 SHARES OUTSTANDING ON MARCH 22, 2002.

DOCUMENTS INCORPORATED BY REFERENCE

Part of Form 10-K	Document Incorporated by Reference
III	Certain sections of the Proxy Statement for Constellation Energy Group, Inc. for the Annual Meeting of Shareholders to be held on May 24, 2002.

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

TABLE OF CONTENTS

		Forward Looking Statements
PART I
	Item 1—Business
			Overview
			Merchant Energy Business
			Merchant Energy Operating Statistics
			BGE
				Electric Business
				Electric Operating Statistics
				Gas Business
				Gas Operating Statistics
				Franchises
			Other Nonregulated Businesses
			Consolidated Capital Requirements
			Environmental Matters
			Employees
	Item 2—Properties
	Item 3—Legal Proceedings
	Item 4—Submission of Matters to a Vote of Security Holders
		Executive Officers of the Registrant (Instruction 3 to Item 401(b) of Regulation S-K)
PART II
	Item 5—Market for Registrant's Common Equity and Related Shareholder Matters
	Item 6—Selected Financial Data
	Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations
	Item 7A—Quantitative and Qualitative Disclosures About Market Risk
	Item 8—Financial Statements and Supplementary Data
	Item 9—Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
PART III
	Item 10—Directors and Executive Officers of the Registrant
	Item 11—Executive Compensation
	Item 12—Security Ownership of Certain Beneficial Owners and Management
	Item 13—Certain Relationships and Related Transactions
PART IV
	Item 14—Exhibits, Financial Statement Schedules and Reports on Form 8-K
	Signatures

Forward Looking Statements

We make statements in this report that are considered forward looking statements within the meaning of the Securities Exchange Act of 1934. Sometimes these statements will contain words such as "believes," "expects," "intends," "plans," and other similar words. These statements are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance or achievements to be materially different from those we project. These risks, uncertainties, and factors include, but are not limited to:

•

the timing and extent of changes in commodity prices for energy including coal, natural gas, oil, and electricity,

•

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

•

the conditions of the capital markets generally, which are affected by interest rates 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 risk management policies and procedures and the ability of our counterparties to satisfy their financial commitments,

•

the liquidity and competitiveness of wholesale markets for energy commodities,

•

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

•

the inability of BGE to recover all its costs associated with providing electric retail customers service during the electric rate freeze period,

•

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

•

regulatory or legislative developments that affect demand for energy, or increase costs, including costs related to nuclear power plants, safety, or environmental compliance,

•

the actual outcome of uncertainties associated with assumptions and estimates using judgment when applying critical accounting policies and preparing financial statements, including factors that are estimated in applying mark-to-market accounting, such as variable contract quantities and the value of mark-to-market assets and liabilities determined using models,

•

cost and other effects of legal and administrative proceedings that may not be covered by insurance, including environmental liabilities, or the outcome of pending appeals regarding the Maryland Public Service Commission's (Maryland PSC) orders on electric deregulation and the transfer of BGE's generation assets to affiliates, and

•

operation of our generation assets in a deregulated market without the benefit of a fuel rate adjustment clause.

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

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

PART I

Item 1. Business

Overview

Constellation Energy Group, Inc. (Constellation Energy) is a North American energy company that conducts its business through various subsidiaries including a merchant energy business that generates and markets wholesale electricity and Baltimore Gas and Electric Company (BGE), a regulated electric and gas public transmission and distribution utility company.

        Constellation Energy was incorporated in Maryland on September 25, 1995. On April 30, 1999, Constellation Energy became the holding company for BGE and its subsidiaries through a share exchange. References in this report to "we" and "our "are to Constellation Energy and its subsidiaries, collectively. References in this report to the "utility business" are to BGE.

        Our merchant energy business includes:

•

fossil, nuclear and hydroelectric generating facilities, interests in domestic power projects and nuclear consulting services, and

•

power marketing, origination transactions, and risk management services.

1

        BGE is a regulated electric and gas public transmission and distribution utility company with a service territory that covers the City of Baltimore and all or part of ten counties in central Maryland. BGE was incorporated in Maryland in 1906. BGE's electric service territory is an area of approximately 2,300 square miles with an estimated population of 2.7 million. BGE's gas service territory is an area of approximately 800 square miles with an estimated population of 2.0 million. There are no municipal or cooperative wholesale customers within BGE's service territory.

        Our other nonregulated businesses include:

•

energy products and services,

•

home products, commercial building systems, and residential and small commercial electric and gas retail marketing,

•

a general partnership, in which BGE is a partner, that provides cooling services for commercial customers in Baltimore,

•

financial investments,

•

real estate holdings and senior-living facilities, and

•

interests in Latin America power generation and distribution projects and investments.

        For a discussion of recent events that have impacted Constellation Energy, please refer to Item 7. Management's Discussion and Analysis—Events of 2001 and Events of 2002 sections. For a discussion of Constellation Energy's strategy, please refer to Item 7. Management's Discussion and Analysis—Strategy section.

Operating Segments

The percentages of revenues, net income, and assets attributable to our operating segments are shown in the tables below. We present information about our operating segments, including certain special costs, in Note 3 to Consolidated Financial Statements. Effective with the first quarter of 2000, we revised our operating segments to reflect the realignments of our organization as a result of the deregulation of electric generation in Maryland. Effective July 1, 2000, the financial results of the electric generation portion of our business are included in the merchant energy business segment. Prior to that date, the financial results are included in the regulated electric segment.

	Unaffiliated Revenues
	Merchant Energy		Regulated Electric		Regulated Gas		Other Nonregulated
2001	16	%	52	%	17	%	15	%
2000	11		55		16		18
1999	7		59		12		22

	Net Income(1)
	Merchant Energy		Regulated Electric		Regulated Gas		Other Nonregulated
2001	70	%	20	%	9	%	1	%
2000	59		29		8		4
1999	18		73		9		—

	Total Assets
	Merchant Energy		Regulated Electric		Regulated Gas		Other Nonregulated & Corp. Items
2001	57	%	27	%	8	%	8	%
2000	56		26		9		9
1999	13		65		9		13

(1)

Excludes special costs included in operations and nonrecurring items as discussed in more detail in Item 8. Financial Statements and Supplementary Data.

Merchant Energy Business

Introduction

Our merchant energy business markets power and manages risks associated with providing energy solutions to meet wholesale customers' needs throughout North America. Our merchant energy business has electric generation assets located in various regions of the United States.

        Our merchant energy business integrates electric generation assets with power marketing and risk management of energy and energy-related commodities. This integration allows our merchant energy business to maximize value across energy products, over geographic regions and over time. Our power marketing operation adds value to our generation assets by providing national market access, market infrastructure, real-time market intelligence, risk management and arbitrage opportunities and transmission and transportation expertise. Generation capacity supports our power marketing operation by providing a source of reliable power supply, enhancing our ability to structure sophisticated products and services for customers, building customer credibility, and providing a physical hedge.

        According to the McGraw-Hill publication "210 Independent Power Companies: Profiles of Industry Players and Projects," dated August 2001, we were ranked the 16^th, 18^th, and 83^rd largest independent power producer in 2001, 2000, and 1999, respectively. Our ranking improved significantly between 1999 and 2000 due to the transfer on July 1, 2000 by BGE of all of its generating assets and related liabilities to two of our nonregulated subsidiaries as a result of deregulation of electric generation in Maryland.

        Currently, our merchant energy business:

•

controls over 11,500 megawatts (MW) of generation capacity, and

2

•

has under construction approximately 2,900 MW of generation capacity.

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

Generation

We have operated in the nonregulated power markets since 1985. At December 31, 2001, our merchant energy business owned 9,174 MW of generation capacity, and had approximately 2,900 MW under construction.

        Effective July 1, 2000, BGE transferred, at book value, the Calvert Cliffs Nuclear Power Plant generating assets, related nuclear decommissioning trust fund, and related liabilities to a nonregulated affiliate. Calvert Cliffs' two units are our largest generating units, totaling 1,685 MW, and are located in Pennsylvania-New Jersey-Maryland Interconnection (PJM). In March 2000, Calvert Cliffs became the first nuclear power plant in the United States to achieve license renewal. The Nuclear Regulatory Commission (NRC) approved a twenty-year license renewal for both units of Calvert Cliffs, extending the license for Unit 1 to 2034 and for Unit 2 to 2036.

        In addition, BGE transferred, at book value, its fossil generating assets and related liabilities and its partial ownership interest in two coal plants and a hydroelectric plant located in Pennsylvania to a nonregulated affiliate. These plants provide electricity from a variety of fuels (coal, oil, gas, and water) that total 4,554 MW and are located in PJM.

        In total, the generating assets transferred by BGE represent about 6,240 MW of generation capacity with a total net book value at June 30, 2000 of approximately $2.4 billion. The output of these plants is managed by Constellation Power Source.

        On November 7, 2001 we purchased the Nine Mile Point Nuclear Station (Nine Mile Point) in Scriba, New York. We purchased 100% of Unit 1 (609 MW) and 82% of Unit 2 (941 MW). Please refer to Note 14 to Consolidated Financial Statements for a discussion of the purchase price. The remaining interest in Nine Mile Point Unit 2 is owned by a subsidiary of the Long Island Power Authority. Unit 1 entered service in 1969 and Unit 2 in 1988. Nine Mile Point is located within the New York Independent System Operator (NYISO).

        The purchase terms include power purchase agreements whereby we agreed to sell 90 percent of our share of the Nine Mile Point plant's output back to the sellers for approximately 10 years at an average price of nearly $35 per megawatt-hour (MWH). The remaining 10% of Nine Mile Point's output will be managed by Constellation Power Source and sold in the wholesale market. The agreements for the output of both units are unit contingent (if the output is not available because the plant is not operating, there is no requirement to provide output from other sources).

        After termination of the power purchase agreements, a revenue sharing agreement will begin and continue through 2021. Under this agreement, which applies only to Unit 2, a strike price is compared to the market price for electricity. If the market price exceeds the strike price, then 80% of this amount is shared with the sellers. The revenue sharing agreement is unit contingent and is based on the operation of the individual units.

        We have an operating agreement with the Long Island Power Authority subsidiary to exclusively operate Unit 2. The Long Island Power Authority subsidiary is responsible for 18% of the operating costs (and decommissioning costs) of Unit 2 and has representation on the management committee which provides certain oversight and review functions.

        The license expires on Unit 1 in 2009 and expires in 2026 on Unit 2. We commenced a license extension initiative for Unit 1 with the objective of obtaining up to 20 years of additional operations.

        During mid-summer of 2001, four natural gas-fired peaking plants with a total generating capacity of 1,100 MW commenced operations. Each plant's output is managed by Constellation Power Source and is sold into the wholesale market. These plants are located in the PJM, Mid-America Interconnected Network (MAIN), and East Central Area Reliability Council (ECAR).

        We also hold up to a 50% ownership interest in 27 operating domestic energy projects that consist of electric generation, fuel processing, or fuel handling facilities and are either qualifying facilities under the Public Utility Regulatory Policies Act of 1978 or otherwise exempt from, or not subject to, the Public Utility Holding Company Act of 1935. Each electric generating plant sells its output to a local utility under long-term contracts.

        These projects include our interests in power projects in California as discussed in more detail in Item 7. Management's Discussion and Analysis—Other States section.

3

        The following table describes our generating facilities:

Plant		Location	Installed Capacity (MW)	% Owned	Capacity (MW) Owned		Primary Fuel
			(at December 31, 2001)		(at December 31, 2001)
Nuclear
	Calvert Cliffs	Calvert Co., MD	1,685	100.0	1,685	(A)	Nuclear
	Nine Mile Point Unit 1	Scriba, NY	609	100.0	609		Nuclear
	Nine Mile Point Unit II	Scriba, NY	1,148	82.0	941	(B)	Nuclear
	Total Nuclear		3,442		3,235
Fossil
	Steam
	Brandon Shores	Anne Arundel Co., MD	1,300	100.0	1,300	(A)	Coal
	Herbert A. Wagner	Anne Arundel Co., MD	1,006	100.0	1,006	(A)	Coal/Oil/Gas
	Charles P. Crane	Baltimore Co., MD	385	100.0	385	(A)	Coal
	Gould Street	Baltimore City, MD	104	100.0	104	(A)	Oil/Gas
	Riverside	Baltimore Co., MD	78	100.0	78	(A)	Gas
	Keystone	Armstrong and Indiana Cos., PA	1,711	21.0	359	(A),(B)	Coal
	Conemaugh	Indiana Co., PA	1,711	10.6	181	(A),(B)	Coal
	ACE	Trona, CA	102	30.3	31	(C)	Coal
	Jasmin	Kern Co., CA	33	50.0	17	(C)	Coal
	POSO	Kern Co., CA	33	50.0	17	(C)	Coal
	Total Steam		6,463		3,478
	Combustion Turbine
	Perryman	Harford Co., MD	350	100.0	350	(A)	Oil/Gas
	Notch Cliff	Baltimore Co., MD	128	100.0	128	(A)	Gas
	Westport	Baltimore City, MD	121	100.0	121	(A)	Gas
	Riverside	Baltimore Co., MD	173	100.0	173	(A)	Oil/Gas
	Philadelphia Road	Baltimore City, MD	64	100.0	64	(A)	Oil
	Charles P. Crane	Baltimore Co., MD	14	100.0	14	(A)	Oil
	Herbert A. Wagner	Anne Arundel Co., MD	14	100.0	14	(A)	Oil
	University Park	Chicago, IL	300	100.0	300		Gas
	Wolf Hills	Bristol, VA	250	100.0	250		Gas
	Handsome Lake	Rockland Twp, PA	250	100.0	250		Gas
	Big Sandy	Neal, WV	300	100.0	300		Gas
	Total Combustion Turbine		1,964		1,964
	Total Fossil		8,427		5,442
Hydroelectric
	Safe Harbor	Safe Harbor, PA	416	66.7	277	(A)	Hydro
	Malacha	Muck Valley, CA	32	50.0	16	(C)	Hydro
	Total Hydroelectric		448		293
Alternative
	Mammoth Lakes G-1	Mammoth Lakes, CA	8	50.0	4		Geothermal
	Mammoth Lakes G-2	Mammoth Lakes, CA	12	50.0	6		Geothermal
	Mammoth Lakes G-3	Mammoth Lakes, CA	12	50.0	6		Geothermal
	Ormesa II	Imperial Valley, CA	17	50.0	9		Geothermal
	Puna I	Hilo, HI	30	50.0	15		Geothermal
	Soda Lake I	Fallon, NV	3	50.0	2		Geothermal
	Soda Lake II	Fallon, NV	13	50.0	7		Geothermal
	Stillwater	Fallon, NV	13	50.0	6		Geothermal
	SEGS IV	Kramer Junction, CA	30	12.0	4		Solar
	SEGS V	Kramer Junction, CA	30	4.0	1		Solar
	SEGS VI	Kramer Junction, CA	30	9.0	3		Solar
	Chinese Station	Sonora, CA	22	45.0	10		Biomass
	Fresno	Fresno, CA	24	50.0	12		Biomass
	Rocklin	Placer Co., CA	24	50.0	12		Biomass
	Central Wayne	Dearborn, MI	22	50.0	11		Municipal Solid Waste
	Colver	Colver Township, PA	110	25.0	28		Waste Coal
	Panther Creek	Nesquehoning, PA	83	50.0	42		Waste Coal
	Sunnyside	Sunnyside, UT	53	50.0	26		Waste Coal
	Total Alternative		536		204	(C)
Total Generating Facilities			12,853		9,174

(A)

The generating assets that were transferred from BGE to nonregulated subsidiaries of Constellation Energy on July 1, 2000.

(B)

These totals reflect our proportionate interest and entitlement to capacity from Nine Mile Point Unit 2 and Keystone and Conemaugh, which include 2 megawatts of diesel capacity for Keystone and 1 megawatt of diesel capacity for Conemaugh.

(C)

These totals reflect our proportionate interest in the entities that own these plants.

4

        The following table describes our processing facilities:

Plant	Location	Installed Capacity (MW)	% Owned	Capacity (MW) Owned	Primary Fuel
		(at December 31, 2001)		(at December 31, 2001)
Gary PCI	Gary, IN	—	12.5	—	Coal Processing
PC Synfuel VA I	Appalachia, VA	—	16.7	—	Synfuel Processing
PC Synfuel WV I	Charleston, WV	—	16.7	—	Synfuel Processing
PC Synfuel WV II	Nettie, WV	—	16.7	—	Synfuel Processing
PC Synfuel WV III	Mayberry, WV	—	16.7	—	Synfuel Processing

        We are currently constructing the following generating facilities. The output of these plants will be managed by Constellation Power Source:

Plant		Location	Capacity (MW)	Type	Primary Fuel	Percent Controlled	Target In Service Date
Rio Nogales		Seguin, TX	800	Combined Cycle	Gas	100	Summer 2002
Holland Energy		Shelby Co., IL	665	Combined Cycle	Gas	100	Summer 2002
Oleander		Brevard Co., FL	680	Combustion Turbine	Gas	100	Summer 2002
High Desert		Victorville, CA	750	Combined Cycle	Gas	100	Summer 2003
	Total		2,895

        The Oleander project has signed a contract to sell 75% of its output to Seminole Electric Cooperative of Tampa, Florida for seven years. Power sales for 50% of the power begin in December 2002, while power sales for the other 25% begin in May 2003. Additionally, Oleander has signed two power purchase agreements with Florida Power and Light Company to begin delivery in June 2002. The first contract to purchase 25% of the plant output runs through April 2003 and the second runs through May 2005. Both Florida Power and Light Company and Oleander have an option to extend for two years at predetermined prices.

        High Desert has signed a contract to sell all of the plant's output on a unit contingent basis to the California Department of Water Resources when it begins operation. This contract is currently the subject of litigation with the Department. The contract has a term of eight years and three months. We discuss the High Desert project in more detail in Item 7. Management's Discussion and Analysis—Other States section.

Fuel Sources

Our power plants use diverse fuel sources. At December 31, 2001, our fuel mix based on capacity owned was:

Fuel	Percentage
Nuclear	35	%
Coal	30
Natural Gas	16
Oil	9
Renewable and Alternative(1)	6
Dual(2)	4

(1)

Includes solar, geothermal, hydro, biomass, and waste-to-energy.



(2)

Switches between natural gas and oil.

Nuclear

Our nuclear plants produce electricity at a relatively low cost. As a result, the costs of replacement energy associated with outages at these plants can be significant. If an unplanned outage were to occur during the summer or winter when demand was at a high level, the replacement power costs could have a material adverse impact on our financial results. Calvert Cliffs will experience extended outages to replace the steam generators for Units 1 and 2 during refueling outages in 2002 and 2003, respectively. We will use appropriate risk management techniques consistent with our business plan and policies to address the issue of replacement power costs.

        The output at Calvert Cliffs over the past five years has been:

	Generation MWH	Capacity Factor
2001	13,648,932	92	%
2000	13,826,046	93
1999	13,309,306	91
1998	13,326,633	91
1997	13,133,441	90

5

        The output at Nine Mile Point over the past five years has been:

	Generation MWH*	Capacity Factor
2001	11,613,519	86	%
2000	11,243,095	83
1999	10,766,425	79
1998	10,837,848	80
1997	9,978,524	74

*represents our proportionate ownership interest

        The supply of fuel for nuclear generating stations includes the:

•

purchase of uranium concentrates,

•

conversion to uranium hexafluoride,

•

enrichment of uranium hexafluoride, and

•

fabrication of nuclear fuel assemblies.

Uranium Concentrates:	We have, either in inventory or under contract, sufficient quantities of uranium to meet 100% of both Calvert Cliffs and Nine Mile Point requirements through 2002, and 25% for Calvert Cliffs and 50% for Nine Mile Point through 2004.
Conversion:	We have contractual commitments providing for the conversion of uranium concentrate into uranium hexafluoride that will meet approximately 75% of Calvert Cliffs' requirements through 2004 and 100% of Nine Mile Point's requirements through 2002, and 50% through 2004.
Enrichment:	We have a contract with the U.S. Enrichment Corporation that provides approximately 50% of Calvert Cliffs' enrichment requirements to 2004 and 100% of Nine Mile Point's requirements through 2002, and 50% through 2004.
Fuel Assembly Fabrication:	We have contracted for the fabrication of fuel assemblies for reloads required through 2013 at Calvert Cliffs and through 2005 for Unit 2 and 2009 for Unit 1 at Nine Mile Point.

        The nuclear fuel market is competitive and we do not anticipate any problem in meeting our requirements.

Storage of Spent Nuclear Fuel—Federal Facilities:    One of the issues associated with the operation and decommissioning of nuclear generating facilities is disposal of spent nuclear fuel. The Nuclear Waste Policy Act of 1982 required the federal government, through the Department of Energy (DOE) by January 31, 1998, to begin to dispose of the utilities' spent nuclear fuel. The federal government has stated that it will not meet that obligation until 2010 at the earliest.

        The 1982 Act assesses a tenth of one cent (one mill) per kilowatt-hour fee on nuclear electricity generated and sold to pay for the costs of disposing of the utilities' spent fuel. We estimate this fee to be approximately $13 million for Calvert Cliffs and $12 million for our portion of Nine Mile Point each year based on expected operating levels. Fees are deposited into the DOE's Nuclear Waste Fund. These fees are paid by the plants' owners.

        In response to the DOE's insufficient progress towards meeting its 1998 obligation, in January 1997, numerous electric utilities requested the United States Court of Appeals for the District of Columbia Circuit, or the DC Circuit, to take certain actions, including ordering the DOE to provide a program that would enable it to meet the January 1998 deadline. In November 1997, the DC Circuit declined to mandate the DOE's performance of its obligations but prohibited the DOE from excusing its delay on the grounds that the delay was unavoidable. In February 1998, several electric utilities requested the DC Circuit to require the DOE to submit a program under which it would begin to immediately remove spent fuel, prohibit the DOE from using the Nuclear Waste Fund to pay damages and allow the utilities to escrow their Nuclear Waste Fund fees until the DOE complied with its obligations. In May 1998, the DC Circuit refused to require the DOE to begin moving spent nuclear fuel and found that utilities should pursue their remedies under their spent nuclear fuel contracts with the DOE. In November 1998, the U.S. Supreme Court denied the DOE's and several states' and state agencies' request for review of the DC Circuit's decisions. A number of utilities have brought suit against the DOE for damages. We are considering whether to seek remedies.

        On February 14, 2002, the Secretary of Energy submitted to the President a recommendation for approval of the Yucca Mountain site for the development of a nuclear waste repository for the geologic disposal of spent nuclear fuel and high level nuclear waste from the nation's defense activities. On February 15, 2002, the President submitted his recommendation of the Yucca Mountain site to Congress. In accordance with the 1982 Act, that submittal triggered a 60-day period for Nevada to file a notice of disapproval of the site and a 90-day legislative period for Congress to override Nevada's disapproval.

Storage of Spent Nuclear Fuel—On-Site Facilities:    Calvert Cliffs has a license from the NRC to operate an on-site independent spent fuel storage facility. We have storage capacity at Calvert Cliffs that will accommodate spent fuel from operations through the year 2006. In addition, we can seek to expand our temporary storage capacity at Calvert Cliffs to meet future requirements. Nine Mile Point does not currently have independent spent fuel storage capacity. Rather, Nine Mile Point's Unit 1 has sufficient storage capacity

6

within the plant until the end of its current operating license. If license renewal is obtained, independent spent fuel storage capability may need to be developed. Nine Mile Point's Unit 2 has sufficient storage capacity within the plant until 2012. After that time independent spent fuel storage capability may need to be developed.

Cost for Decommissioning Uranium Enrichment Facilities:    The Energy Policy Act of 1992 contains provisions requiring domestic nuclear utilities to contribute to a fund for decommissioning and decontaminating uranium enrichment facilities that had been operated by DOE. These contributions are generally payable over a 15-year period with escalation for inflation and are based upon the amount of uranium enriched by DOE for each utility through 1992. The 1992 Act provides that these costs are recoverable through utility service rates. BGE is solely responsible for these costs as they relate to Calvert Cliffs. The sellers of the Nine Mile Point plant and a subsidiary of the Long Island Power Authority will remain responsible for the costs relating to the Nine Mile Point plant. Numerous utilities, including BGE, have challenged these fees in several venues, all of which are currently pending.

Cost for Decommissioning:    When our nuclear plants cease operation, we will be obligated to decommission them. Both Calvert Cliffs and Nine Mile Point are required by the NRC to financially prepare for this decommissioning. When BGE transferred all of its nuclear generating assets to an affiliate, it also transferred the trust fund it had established to pay for decommissioning Calvert Cliffs. At December 31, 2001, the trust fund had a balance of approximately $241.0 million. Under the Maryland PSC's order regarding the deregulation of electric generation, BGE ratepayers must pay a total of $520 million, in 1993 dollars, adjusted for inflation, to decommission Calvert Cliffs through fixed annual collections of approximately $18.7 million until June 30, 2006, and thereafter in an annual amount determined by reference to specified factors. BGE is collecting this amount on behalf of Calvert Cliffs. Any costs to decommission Calvert Cliffs in excess of the $520 million discussed above must be paid by Calvert Cliffs. If BGE ratepayers have paid more than this amount at the time of decommissioning, Calvert Cliffs must refund the excess. If the cost to decommission Calvert Cliffs is less than the amount BGE's ratepayers are obligated to pay, Calvert Cliffs may keep the difference.

        The sellers of Nine Mile Point transferred a $441.7 million decommissioning trust fund at the time of sale. In return, Nine Mile Point will assume all liability for the costs to decommission Unit 1 and 82% of the cost to decommission Unit 2. We believe that this amount is adequate to cover the currently estimated costs that we are responsible for in decommissioning Nine Mile Point to a greenfield status (restoration of the site so that it substantially matches the natural state of the surrounding properties and the site's intended use).

Coal
We purchase the majority of our coal under supply contracts with mining operators, and we get the rest through spot purchases. We believe that we will be able to renew supply contracts as they expire or enter into contracts with other coal suppliers. During 2001, coal prices increased and we expect to incur additional costs in the future to operate our coal generating facilities due to this increase in coal costs. Our primary coal burning facilities have the following requirements:

	Annual Coal Requirement (tons)	Special Coal Restrictions
Brandon Shores Units 1 and 2     (combined)	3,500,000	Sulfur content less than 0.8%
Crane Units 1 and 2     (combined)	850,000	Low ash melting temperature
Wagner Units 1 and 2     (combined)	1,100,000	Sulfur content no more than 1%

        Coal deliveries to these facilities are made by rail and barge. The coal we use is produced from mines located in central and northern Appalachia.

        All of the Conemaugh and Keystone plants' annual coal requirements are purchased from regional suppliers on the open market. The sulfur restrictions on coal are approximately 2.5% for the Keystone plant and approximately 4.5% for the Conemaugh plant.

        The annual coal requirements for the ACE, Jasmin, and POSO plants, which are located in California, are supplied under contracts with mining operators. Each plant is restricted to coal with sulfur content less than 4%.

Oil
Under normal burn practices, our requirements for residual fuel oil (No. 6) amount to approximately 1,500,000 to 2,000,000 barrels of low-sulfur oil per year. Deliveries of residual fuel oil are made directly into our barges from the suppliers' Baltimore Harbor marine terminal for distribution to the various generating plant locations. Also, based on normal burn practices, we also require approximately 5,000,000 to 6,000,000 gallons of distillates (No. 2 oil and kerosene) annually, but these requirements can increase based on adverse weather and operating requirements. Distillates are purchased from the suppliers' Baltimore truck terminals for distribution to the various generating plant locations. We have contracts with various suppliers to purchase oil at spot prices, and for future delivery, to meet our requirements.

7

Gas
We purchase natural gas and transportation, as necessary, for electric generation at certain plants. Some of our gas-fired units can use residual fuel oil or distillates instead of gas. Gas is purchased under contracts with suppliers on the spot market and for future delivery. We believe that we will be able to obtain adequate quantities of gas to meet our requirements.

        Our merchant energy business manages its fuel risks as part of risk management for its portfolio of energy purchases and sales obligations.

Power Marketing

Through Constellation Power Source, Inc. (CPS) we are a leading power marketer in North America. CPS provides power marketing and risk management services to wholesale customers to assist them in managing their energy needs. Power Markets Weekly ranked CPS as the 13^th largest North American power marketer for 2001 based on the total MWH of electricity sold. In 2001, CPS sold 173.3 million MWH.

        CPS focuses its activities on origination transactions tailored to meet customers' energy needs. It targets full requirements load service customers such as utilities, municipalities, cooperatives, and retail aggregators in regional markets in which end user electricity rates have been deregulated and thereby separated from the cost of generation supply. These markets include: New England, the Mid-Atlantic and Texas. Contracts with these customers generally extend from one to ten years, but some can be longer. Among the products and services that CPS provides are full requirements electricity service to utilities that have sold their generating assets and management of the fuel procurement and electricity output of generation companies.

        CPS supplies standard offer electric service to BGE. CPS' contract with BGE obligates it to supply all of the requirements for energy, capacity, and ancillary services needed to meet all of BGE's retail customers' electricity needs through June 30, 2003 and 90% of such requirements from July 1, 2003 through June 30, 2006. For 2001, the peak load supplied to BGE was 6,490 MW. CPS meets the requirements of this contract through electricity purchases from affiliates and from the market.

        CPS also supplies standard offer electric service to several distribution utilities and retail aggregators in New England and Texas to supply their retail customers' needs. CPS' current load-serving obligations expire between 2002 and 2009. The peak load delivered to these customers for 2001 was 2,909 MW.

        To meet customers' requirements, CPS purchases electricity from various sources, including:

•

affiliates that own generation assets,

•

tolling contracts, which provide us the right, but not the obligation, to purchase power at a price linked to the variable cost of production, including fuel, with generation companies that generally extend from several months to several years but can be longer,

•

bilateral agreements with third parties that generally extend for less than one year but can be longer, or

•

regional power pools.

        CPS also markets electricity generated by our power plants that is not committed to third parties under long-term contracts.

        Since its inception in 1997, CPS has experienced growth in power sales as reported to the Federal Energy Regulatory Commission (FERC). In 2001, CPS sold 173.3 million MWH of electricity, compared to 162.3 million MWH in 2000, and 69.8 MWH in 1999. Excluding BGE, no one customer or small group of customers accounts for a material portion of CPS' electric power purchases or sales.

        In addition, CPS buys and sells natural gas, oil, and other energy-related commodities to support our merchant energy business activities. The majority of this activity is related to:

•

the purchase of natural gas required to produce electricity for plants owned by affiliates or plants over which CPS has contractual control, and

•

the hedge of electricity positions.

        The primary sources of these purchases and sales are other merchant energy companies, commodities trading companies, natural gas marketing companies, and natural gas production companies.

        CPS engages in power marketing and risk management of energy and energy-related commodities in order to manage its portfolio of energy purchases and sales to customers through origination transactions, to obtain market intelligence, and to take advantage of arbitrage opportunities that exist across different markets. These activities involve the use of a variety of instruments, including:

•

forward contracts (which commit it to purchase or sell energy commodities in the future),

•

swap agreements (which require payments to or from counterparties based upon the difference between two prices for a predetermined contractual (notional) quantity),

•

option contracts (which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price), and

•

futures contracts (which are exchange traded standardized commitments to purchase or sell a commodity or financial instrument, or make a cash settlement, at a specified price and future date).

        Active portfolio management allows CPS to manage and hedge its fixed-price purchase and sale commitments; provide fixed-price commitments to customers and suppliers; reduce exposure to the

8

volatility of cash market prices; and hedge fuel requirements at generation facilities.

        CPS' business subjects it to various business risks, including market risk (risk created by volatile and fluctuating energy prices), credit risk (risk of counterparty nonperformance or default), delivery risk (risk related to physical delivery of energy to meet customers' needs), and operational risk (risk related to lack of proper segregation of duties and lack of clearly defined policies and procedures). CPS utilizes a trading and risk management system as part of its internal control structure to support its business activity and manage its risks.

        CPS monitors and manages its risk exposures through separate, but complementary financial, operational, and credit reporting systems. Constellation Energy's board of directors establishes parameters for the risks that CPS can undertake and risk levels are monitored daily by management and our Chief Risk Officer. In addition, CPS maintains segregation of duties, with credit review and risk monitoring functions performed by groups that are independent from revenue producing groups. For additional information on market and credit risk, see Item 7. Management's Discussion and Analysis—Market Risk section.

Nuclear Consulting Services

Constellation Nuclear Services provides license renewal-related services to the nuclear utility industry, along with plant life cycle support services, including aging management, spent fuel management, steam generator life optimization and project management and engineering. Constellation Nuclear Services' strategy is to capitalize on the needs of the nuclear utility industry that are evolving from the aging of the nuclear fleet. Constellation Nuclear Services intends to use its unique capabilities to support the rapidly evolving services market created by the deregulation that has taken place in the utility industry. Constellation Nuclear Services' key competitors are traditional nuclear services suppliers.

Competition

We face intense competition in all phases of our merchant energy business. We encounter competition from companies of various sizes, having varying levels of experience, financial and human resources, and differing strategies.

        With respect to power generation, we compete in the development and operation of energy-producing projects, and our competitors in this business are both domestic and international organizations, many of whom have extensive and diversified operating expertise including various utilities, industrial companies and independent power producers (including affiliates of utilities), some of which have financial resources that are greater than ours. In recent years, the industry has been characterized by increasingly strong competition with respect to the acquisition of existing electric generating facilities. This includes a trend away from negotiated transactions and towards competitive bidding.

        In our merchant energy business, we compete with international, national and regional full service energy providers, merchants and producers, to obtain competitively priced supplies from a variety of sources and locations and to utilize efficient transmission or transportation. We face competition in the market for energy, capacity, and ancillary services. We principally compete on the basis of the price, reliability and availability of our products.

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

        Increased competition that resulted from some of these initiatives in several states contributed in some instances to a reduction in electricity prices and put pressure on electric utilities to lower their costs, including the cost of purchased electricity. However, some states that were considering deregulation have slowed their plans or postponed consideration. While our merchant energy business may be affected by the slow down in deregulation, the FERC initiatives regarding the formation of larger Regional Transmission Organizations could provide other merchant energy business opportunities. Additionally, our business is rapidly becoming more competitive due to technological advances in power generation, e-commerce enabling new ways of conducting business, the increased role of full service providers, and increased efficiency of energy markets.

        In general, however, we believe that our experience and expertise in assessing and managing risk will help us to remain competitive during volatile or otherwise adverse market circumstances.

9

Merchant Energy Operating Statistics

			2001		2000		1999		1998		1997
Mark-to-Market Energy Assets (In millions)			$	2,218.2	$	2,522.4	$	373.4	$	133.0	$	9.4
Mark-to-Market Energy Liabilities (In millions)				1,799.8		1,994.5		225.1		99.0		8.6
Revenues (In millions)
	Standard Offer Service Revenue from BGE		$	1,269.0	$	691.0	$	—	$	—	$	—
	Other Generation Revenue			314.1		171.9		124.3		129.4		108.1
	Mark-to-Market Energy Revenues			175.8		151.5		147.7		47.5		2.6
	Other Revenue			6.6		11.3		5.3		6.7		2.3
		Total Revenue	$	1,765.5	$	1,025.7	$	277.3	$	183.6	$	113.0
Generated (In millions)—MWH				37.4		18.8		1.3		1.3		1.2

Operating statistics do not reflect the elimination of intercompany transactions.

Baltimore Gas and Electric Company

BGE is a regulated electric and gas public transmission and distribution utility company with a service territory that covers the City of Baltimore and all or part of ten counties in central Maryland. BGE's electric service territory includes an area of approximately 2,300 square miles with an estimated population of 2.7 million. BGE's gas service territory includes an area of approximately 800 square miles with an estimated population of 2.0 million. Our electric and gas revenues come from many customers—residential, commercial, and industrial. In 2001, our largest electric customer provided approximately three percent of our total electric revenues. In 2001, our largest gas customer provided one percent of our total gas revenues. As discussed below, BGE's regulated electric business was significantly impacted by the July 1, 2000 deregulation of electric generation and implementation of customer choice in Maryland.

        Weather affects the demand for electricity and gas. Very hot summers and very cold winters increase demand. Mild weather reduces demand. Residential sales for our regulated businesses are impacted more by weather than commercial and industrial sales, which are mostly affected by business needs for electricity and gas. However, the Maryland PSC allows us to record a monthly adjustment to our regulated gas business revenue to eliminate the effect of abnormal weather conditions.

Electric Business

Electric Regulatory Matters and Competition

Restructuring Order

On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition Act of 1999 (the Act) and accompanying tax legislation that significantly restructured Maryland's electric utility industry and modified the industry's tax structure.

        In the Restructuring Order discussed below, the Maryland PSC addressed the major provisions of the Act. The accompanying tax legislation is discussed in detail in Note 5 to Consolidated Financial Statements.

        On November 10, 1999, the Maryland PSC issued a Restructuring Order that resolved the major issues surrounding electric restructuring, accelerated the timetable for customer choice, and addressed the major provisions of the Act. The Restructuring Order also resolved the electric restructuring proceeding (transition costs, customer price protections, and unbundled rates for electric services) and a petition filed in September 1998 by the Office of People's Counsel to lower our electric base rates. The major provisions of the Restructuring Order are discussed in Note 5 to Consolidated Financial Statements. As a result of the deregulation of electric generation, the following occurred effective July 1, 2000:

•

All customers can choose their electric energy supplier. BGE will provide a standard offer service for customers that do not select an alternative supplier. In either case, BGE will continue to deliver electricity to all customers in areas traditionally served by BGE.

•

BGE reduced residential base rates by approximately 6.5%, on average about $54 million a year. These rates will not change before July 2006.

•

BGE transferred, at book value, its nuclear generating assets, its nuclear decommissioning trust fund, and related liabilities to Calvert Cliffs Nuclear Power Plant, Inc. In addition, BGE transferred, at book value, its fossil generating assets and related liabilities and its partial ownership interest in two coal plants and a hydroelectric plant located in Pennsylvania to Constellation Power Source Generation. In total, these generating assets

10

represent about 6,240 megawatts of generation capacity with a total net book value at June 30, 2000 of approximately $2.4 billion.

•

BGE assigned approximately $47 million to Calvert Cliffs Nuclear Power Plant, Inc. and $231 million to Constellation Power Source Generation of tax-exempt debt related to the transferred assets.

•

Constellation Power Source Generation issued approximately $366 million in unsecured promissory notes to BGE. All of these notes have been repaid by Constellation Power Source Generation. The proceeds were used to service the current maturities of certain BGE long-term debt.

•

BGE transferred equity associated with the generating assets to Calvert Cliffs Nuclear Power Plant, Inc. and Constellation Power Source Generation.

•

The fossil fuel and nuclear fuel inventories, materials and supplies, and certain purchased power contracts of BGE were also assumed by these subsidiaries.

Standard Offer Service

Effective July 1, 2000, BGE provides standard offer service to customers at fixed rates over various time periods during the transition period through June 30, 2006 for those customers that do not choose an alternate supplier. In addition, the electric fuel rate was discontinued effective July 1, 2000. CPS is providing BGE with the energy and capacity required to meet its standard offer service obligations through June 30, 2003. Beginning July 1, 2003, CPS will provide 90% and Allegheny Energy Supply Company, LLC will provide the remaining 10% of the energy and capacity required for BGE to meet its standard offer service obligations until June 30, 2006. Alternatively, BGE delivers electricity for its customers that choose their own suppliers. In addition to the delivery service, BGE provides meter readings, billing, emergency response, regular maintenance, and balancing.

        We discuss the market risk of our regulated electric business in more detail in Item 7. Management's Discussion and Analysis—Market Risk section.

        Prior to July 1, 2000, BGE deferred (included as an asset or liability on the Consolidated Balance Sheets and excluded from the Consolidated Statements of Income) the difference between its actual costs of fuel and energy and what it collected from customers under the fuel rate in a given period. Effective July 1, 2000, the fuel rate clause was discontinued under the terms of the Restructuring Order. In September 2000, the Maryland PSC approved the collection of the $54.6 million accumulated difference between BGE's actual costs of fuel and energy and the amounts collected from customers that were deferred under the electric fuel rate clause through June 30, 2000. BGE collected this accumulated difference from customers over the twelve-month period ending October 2001.

        BGE's electric transmission and distribution business continues to be regulated by the Maryland PSC although electric delivery rates are fixed until June 30, 2004 for industrial and commercial customers and until June 30, 2006 for residential customers. However, the electric transmission and distribution services are facing competition from alternative energy sources that include on-site generation and cogeneration projects. In future years, emerging technologies, including fuel cells and solar panels, may also become a competitive factor.

Electric Load Management

BGE implemented various programs for use when system-operating conditions or market economics indicate that a reduction in load would be beneficial. We refer to these programs as active load management programs. These programs include:

•

customer-owned generation and curtailable service for large commercial and industrial customers,

•

air conditioning control for residential and commercial customers, and

•

residential water heater control.

        BGE generally activates these programs on summer days when demand and/or wholesale prices are relatively high. The reduction in the summer 2001 peak load from active load management was approximately 425 MW.

Transmission and Distribution Facilities

BGE maintains nearly 1,300 circuit miles of transmission lines throughout central Maryland. BGE also maintains nearly 21,500 circuit miles of distribution lines. Its transmission facilities are connected to those of neighboring utility systems as part of the PJM Interconnection. Under the PJM agreement, BGE uses the interconnected facilities for substantial energy interchange and capacity transactions as well as emergency assistance.

        In December 1999, FERC issued Order 2000, amending its regulations under the Federal Power Act to advance the formation of regional transmission organizations. The regulations require that each public utility that owns, operates, or controls facilities for the transmission of electric energy in interstate commerce make certain filings with respect to forming and participating in a regional transmission organization. FERC also identified the minimum characteristics and functions that a transmission entity must satisfy in order to be considered a regional transmission organization.

        We discuss Order 2000 in more detail in Item 7. Management's Discussion and Analysis—FERC Regulation—Regional Transmission Organizations section.

11

Electric Operating Statistics

			2001		2000(A)		1999		1998		1997
Revenues (In millions)
	Residential		$	885.3	$	922.6	$	975.2	$	948.6	$	932.5
	Commercial			903.0		926.2		939.3		912.9		892.6
	Industrial			218.1		203.6		204.3		211.5		211.9
		System Sales	$	2,006.4	$	2,052.4	$	2,118.8	$	2,073.0	$	2,037.0
Sales (In thousands)—MWH
	Residential			11,714		11,675		11,349		10,965		10,806
	Commercial			14,147		14,042		13,565		13,219		12,718
	Industrial			4,445		4,476		4,350		4,583		4,575
		System Sales		30,306		30,193		29,264		28,767		28,099
Customers (In thousands)
	Residential			1,040.5		1,033.4		1,021.4		1,009.1		1,001.0
	Commercial			110.9		108.9		107.7		106.5		105.9
	Industrial			5.0		5.0		4.7		4.6		4.5
		Total		1,156.4		1,147.3		1,133.8		1,120.2		1,111.4

(A)

Operating statistics reflect generation function as part of regulated electric operations through June 30, 2000.

Operating statistics do not reflect the elimination of intercompany transactions.

Gas Business

Gas Regulatory Matters and Competition

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

        BGE buys all gas that it resells directly from various suppliers (rather than pipeline companies) and arranges separately for transportation and storage. Alternatively, BGE can transport gas for its customers. BGE also participates in the interstate markets, by releasing pipeline capacity or bundling pipeline capacity with gas for off-system sales.

        BGE's customers have the option for delivery service across our distribution system so that they may make direct purchase and transportation arrangements with suppliers and pipelines. In addition to the delivery service, BGE also provides these customers with meter readings, billing, emergency response, regular maintenance, and balancing.

        Approximately 54% of the gas on our distribution system is for customers using delivery service. We charge all our delivery service customers fees to recover the fixed costs for the transportation service we provide. These fees are the same as the base rate charged for gas sales.

        Delivery service customers may choose to purchase gas from several different suppliers, including our subsidiary, BGE Home Products & Services, Inc. The basis of competition for delivery service customers is primarily commodity price.

        As part of our response to the increase in competition in the natural gas business, earnings from off-system gas sales and capacity release revenues are shared between shareholders and customers. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas outside our service territory. We make these sales as part of a program to balance our supply of, and cost of, natural gas. In addition, we have a market based rates incentive mechanism for gas we sell on our system.

        Under market based rates, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers. Effective November 2001, the Maryland PSC approved an order that modifies certain provisions of the market-based rates incentive mechanism. These provisions require that BGE secure fixed-price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for the November through March period. These fixed price contracts are not subject to sharing under the market-based rates incentive mechanism.

12

        The Maryland PSC authorized a $6.4 million annual increase in our gas base rates effective June 22, 2000.

Gas Operations

We distribute natural gas purchased directly from many producers and marketers. We have transportation and storage agreements as shown below. These agreements are on file with the FERC. The gas is transported to our city gates, under various transportation agreements, by:

•

Columbia Gas Transmission Corporation,

•

Dominion Transmission Inc., and

•

Transcontinental Gas Pipe Line Corporation.

        To transport gas from the pipelines that supply gas to the pipelines that are connected to our city gates as mentioned above, we also have transportation capacity under contract with:

•

Texas Gas,

•

Columbia Gulf Transmission Company, and

•

ANR Pipeline Company.

        We have storage service agreements with:

•

Columbia Gas Transmission Corporation,

•

Dominion Transmission Inc., and

•

ANR Pipeline Company.

        Our current pipeline firm transportation entitlements to serve our firm loads are 284,053 DTH per day during the winter period and 259,053 DTH per day during the summer period. We use the firm transportation capacity to move gas from the Gulf of Mexico, Louisiana, south central regions of Texas, and Canada to our city gates. We can arrange short-term contracts or exchange agreements with other gas companies in the event of short-term emergencies.

        We have three market area storage contracts to manage weather sensitive gas demand during the winter period. Our current maximum storage entitlements are 235,080 DTH per day. To supplement our gas supply at times of heavy winter demands and to be available in temporary emergencies affecting gas supply, we have:

•

a liquefied natural gas facility for the liquefaction and storage of natural gas with a total storage capacity of 1,075,645 DTH and a planned daily capacity of 287,988 DTH, and

•

a propane air facility with a mined cavern with a total storage capacity equivalent to 545,000 DTH and a planned daily capacity of 85,000 DTH.

        We have under contract sufficient volumes of propane for the operation of the propane air facility and are capable of liquefying sufficient volumes of natural gas during the summer months for operation of our liquefied natural gas facility during winter emergencies.

13

Gas Operating Statistics

				2001		2000		1999		1998		1997
Gas Output (In thousands)—DTH
	Purchased				47,904		48,518		49,082		47,972		62,988
	LNG Withdrawn from Storage				507		874		463		268		484
	Produced				153		261		486		46		541
			Total Output		48,564		49,653		50,031		48,286		64,013
	Delivery Service Gas (A)				57,001		67,658		59,494		55,608		52,629
	Off-system Sales (B)				20,012		22,456		15,543		16,724		14,759
			Total		125,577		139,767		125,068		120,618		131,401
Peak Day Send Out (DTH)					668,600		795,700		727,800		658,400		765,000
Capability on Peak Day (DTH)					937,800		825,100		836,600		833,000		870,000
Revenues (In millions)
	Residential
		Excluding Delivery Service		$	378.4	$	328.4	$	298.1	$	279.2	$	321.7
		Delivery Service			16.3		23.5		11.5		4.9		0.5
	Commercial
		Excluding Delivery Service			115.5		97.9		79.3		75.6		113.5
		Delivery Service			21.4		25.8		24.4		19.4		12.9
	Industrial
		Excluding Delivery Service			12.8		10.9		8.2		8.0		11.4
		Delivery Service			13.8		16.3		16.1		16.0		17.2
	System Sales				558.2		502.8		437.6		403.1		477.2
	Off-system Sales				113.6		101.0		42.9		40.9		37.5
	Other				8.9		7.8		7.6		7.1		6.9
			Total	$	680.7	$	611.6	$	488.1	$	451.1	$	521.6
Sales (In thousands)—DTH
	Residential
		Excluding Delivery Service			33,147		34,561		34,272		33,595		39,958
		Delivery Service			7,201		9,209		4,468		1,890		205
	Commercial
		Excluding Delivery Service			12,334		13,186		11,733		11,775		18,435
		Delivery Service			25,037		22,921		20,288		16,633		12,964
	Industrial
		Excluding Delivery Service			1,386		1,386		1,367		1,412		2,016
		Delivery Service			23,872		32,382		33,118		34,798		38,791
	System Sales				102,977		113,645		105,246		100,103		112,369
	Off-system Sales				20,012		22,456		15,543		16,724		14,759
			Total		122,989		136,101		120,789		116,827		127,128
Customers (In thousands)
	Residential				558.7		553.7		543.5		532.5		524.5
	Commercial				40.2		40.1		39.9		39.6		39.3
	Industrial				1.4		1.4		1.3		1.3		1.3
			Total		600.3		595.2		584.7		573.4		565.1

For the periods presented, we achieved an all-time peak day sendout of 795,700 DTH on January 17, 2000.

(A)

Delivery service gas is gas purchased by customers directly from suppliers for which we receive a fee for transportation through our system.

(B)

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

        We discuss these programs further in the Gas Regulatory Matters and Competition section.

Operating statistics do not reflect the elimination of intercompany transactions.

14

Franchises

BGE has nonexclusive electric and gas franchises to use streets and other highways that are adequate and sufficient to permit us to engage in our present business. All such franchises, other than the gas franchises in Manchester, Hampstead, Perryville, Sykesville, Havre de Grace, Mt. Airy, and Montgomery

and Frederick Counties, are unlimited as to time. The gas franchises for these jurisdictions expire at various times from 2015 to 2087, except for Havre de Grace which has the right, exercisable at twenty-year intervals from 1907, to purchase all of our gas properties in that municipality. Conditions of the franchises are satisfactory.

Other Nonregulated Businesses

Energy Products and Services

Constellation Energy Source, Inc. offers energy products and services designed primarily to provide solutions to the energy needs of commercial and industrial customers. These energy products and services include:

•

a full range of heating, ventilation, air conditioning, and energy services,

•

energy consulting and power-quality services,

•

services to enhance the reliability of individual electric supply systems, and

•

customized financing alternatives.

Home Products, Commercial Building Systems, and Electric and Gas Retail Marketing

BGE Home Products & Services, Inc. and subsidiaries offer services to residential, commercial, and industrial customers. These services include:

•

the sale and service of electric and gas appliances,

•

home improvements,

•

the sale and service of heating, air conditioning, plumbing, electrical, and indoor air quality systems, and

•

electric and natural gas retail marketing.

ComfortLink

ComfortLink provides cooling services using a central chilled water distribution system to commercial customers in Baltimore.

Other

In addition, our other nonregulated businesses include financial investments, real estate and senior living facilities, and interests in Latin American power generation and distribution projects and investments. As part of our strategy to focus management's attention and our capital resources on our core energy businesses, we have decided to sell six real estate projects without further development and all of our 18 senior living facilities and accelerate our exit strategies for two other real estate projects. We have also decided to accelerate our exit strategy for our investment in a distribution company in Panama.

        We describe our other nonregulated businesses further in Item 7. Management's Discussion and Analysis—Introduction section.

Consolidated Capital Requirements

Our business requires a great deal of capital. Our total capital requirements for 2001 were $2,089 million. Of this amount, $1,850 million was used in our nonregulated businesses and $239 million was used in our utility operations. We estimate our total capital requirements for the years 2002 and 2003 to be:

•

$824 million in 2002, and

•

$544 million in 2003.

        We continuously review and change our capital expenditure programs, so actual expenditures may vary from the estimates above. We discuss our capital requirements further in Item 7. Management's Discussion and Analysis—Capital Resources section.

Environmental Matters

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

•

air quality,

•

water quality,

•

chemical and waste management and disposal, and

•

other environmental matters.

        The development (involving site selection, environmental assessments, and permitting), construction, acquisition, and operation of electric generating and distribution facilities are subject to extensive federal, state, and local environmental and land use laws and regulations. From the beginning phases of siting and developing, to the ongoing operation of existing or new electric generating and distribution facilities, our activities involve compliance with diverse laws and regulations that address emissions and impacts to air and water, special, protected and cultural resources (such as wetlands, endangered species, and archeological/historical resources), chemical, and waste handling and noise impacts. Our activities require complex and often lengthy processes to obtain approvals, permits, or licenses for new, existing, or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires preparation of release prevention plans and emergency response procedures. As new laws or

15

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

        Our capital expenditures (excluding allowance for funds used during construction) were approximately $205 million during the five-year period 1997-2001 to comply with existing environmental standards and regulations, and we estimate that the future incremental capital expenditures (excluding allowance for funds used during construction) necessary to comply with existing environmental standards and regulations will be approximately:

•

$69 million in 2002, and

•

$16 million in 2003.

Clean Air

Clean Air Act

The Clean Air Act affects both existing generating facilities and new projects. The Clean Air Act and many state laws require significant reductions in SO₂ (sulfur dioxide) and NO_x (nitrogen oxide) emissions that result from burning fossil fuels. The Clean Air Act also contains other provisions that could materially affect some of our projects. Various provisions may require permits, inspections, or installation of additional pollution control technology. Certain of these provisions are described in more detail below. Because our generation portfolio is diverse, both in the mix of fuels used to generate electricity, as well as in the age of various facilities, the Clean Air Act requirements have different impacts in terms of compliance costs for each of our projects. Many of these compliance costs may be substantial, as described in more detail below. In addition, the Clean Air Act contains many enforcement tools, ranging from broad investigatory powers to civil, criminal, and administrative penalties and citizen suits. These enforcement provisions also include enhanced monitoring, recordkeeping, and reporting requirements for both existing and new facilities.

        The Clean Air Act creates a marketable commodity called an SO₂ "allowance." All non-exempt facilities over 25 megawatts that emit SO₂ must obtain allowances in order to operate after 1999. Each allowance gives the owner the right to emit one ton of SO₂. All non-exempt existing facilities have been allocated allowances based on a facility's past production and the statutory emission reduction goals. If additional allowances are needed for new facilities, they can be purchased from facilities having excess allowances or from S0₂ allowance banks. Our projects comply with the S0₂ allowance caps through the purchase of allowances, use of emission control devices, or by qualifying for exemptions. We believe that the additional costs of obtaining allowances needed for future generation projects should not materially affect our ability to build, acquire, and operate them.

        The Clean Air Act also requires states to impose annual operating permit fees. These fees are based on the tons of pollutants emitted from a generating facility and vary based on the type of facility. For example, fees will typically be greater for coal-fired plants than for natural gas-fired plants. Our portfolio includes coal-fired plants and gas-fired plants, as well as plants using renewable energy sources such as solar and geothermal, which have far less emissions. The fees do not significantly increase our costs.

        The Ozone Transport Assessment Group, composed of state and local air regulatory officials from the 37 Mid-Western and Eastern states, has recommended additional NO_X emission reductions that go beyond current federal standards. These recommendations include reductions from utility and industrial boilers during the summer ozone season.

        As a result of the Ozone Transport Assessment Group's recommendations, on October 27, 1998, the Environmental Protection Agency (EPA) issued a rule requiring 22 Eastern states and the District of Columbia to reduce emissions of NO_X (a precursor of ozone). Among other things, the EPA's rule establishes an ozone season, which runs from May through September, and a NO_X emission budget for each state, including Maryland and Pennsylvania. The EPA rule requires states to implement controls sufficient to meet their NO_X budget by May 30, 2004. Coal-fired power plants are a principal target of NO_X reductions under this initiative, however, some of our newer coal-fired plants may already meet the EPA expectations and will not require the same amount of capital expenditures.

        Many of the generation facilities are subject to NO_X reduction requirements under the EPA rule including those located in Maryland and Pennsylvania. This regulation affects both new and existing facilities causing additional capital investment. At the Brandon Shores facility we have installed, and at our Wagner facility we are installing, emission reduction equipment by May 2002 to meet Maryland regulations issued pursuant to EPA's rule. The owners of the Keystone plant in Pennsylvania are installing emissions reduction equipment by 2003 to meet Pennsylvania regulations issued pursuant to EPA's rule. We estimate that the equipment needed at these plants will cost approximately $290 million. Through December 31, 2001, we have spent approximately $200 million.

        In July 1997, the EPA published new National Ambient Air Quality Standards for very fine particulates and revised standards for ozone attainment. In 1999, these new standards were successfully challenged in court. The EPA appealed the 1999 court rulings to the Supreme Court. In February 2001, the Supreme Court upheld EPA's authority to issue the standards. However, the Supreme Court sent the case back to the lower court and EPA for further proceedings on implementation issues related to the revised ozone standard. The lower court will also address remaining challenges to the fine particulate standard. While these standards may require increased controls at our fossil

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generating plants in the future, implementation, if required, could be delayed for several years. We cannot estimate the cost of these increased controls at this time because the states, including Maryland, Pennsylvania, and California, still need to determine what reductions in pollutants will be necessary to meet the EPA standards.

        Over the past two years, the EPA and several states have filed suits against a number of coal-fired power plants in Mid-Western and Southern states alleging violations of the deterioration prevention and non-attainment provisions of the Clean Air Act's new source review requirements. In 2000, using its broad investigatory powers under Section 114 of the Clean Air Act, the EPA requested information relating to modifications made to our Brandon Shores, Crane, and Wagner plants in Baltimore, Maryland. The EPA also sent similar, but narrower, information requests to two of our newer Pennsylvania waste-coal burning plants. We have responded to the EPA and are waiting to see if the EPA takes any further action. This information is to determine compliance with the Clean Air Act and state implementation plan requirements, including potential application of federal New Source Performance Standards. In general, such standards can require the installation of additional air pollution control equipment upon the major modification of an existing plant. Although there have not been any new source review-related suits filed against our facilities, there can be no assurance that any of them will not be the target of an action in the future. Based on the levels of emissions control that the EPA and/or states are seeking in these new source review enforcement actions, we believe that material additional costs and penalties could be incurred, and/or planned capital expenditures could be accelerated, if the EPA was successful in any future actions regarding our facilities.

        The Clean Air Act requires the EPA to evaluate the public health impacts of emissions of mercury, a hazardous air pollutant, from coal-fired plants. The EPA has decided to control mercury emissions from coal-fired plants. Compliance could be required by approximately 2007. Final regulations are expected to be issued in 2004 and would affect all coal-fired boilers. The cost of compliance could be material.

        Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. The related Kyoto Protocol was signed by the United States but has not yet been ratified by the U.S. Senate. Future initiatives on this issue and the ultimate effects of the Kyoto Protocol on us are unknown at this time. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies. Fossil fuel-fired power plants, however, are significant sources of carbon dioxide emissions, a principal greenhouse gas. Therefore, our compliance costs with any mandated federal greenhouse gas reductions in the future could be significant.

Clean Water Act

Our facilities are subject to a variety of state and federal regulations governing existing and potential water/wastewater and stormwater discharges from the facilities. Generally, federal regulations promulgated through the Clean Water Act govern overall water/wastewater and stormwater discharges through permits often referred to as National Pollution Discharge Elimination System or NPDES permits. State water quality regulations require us to, among other things, define procedures to determine compliance with each state's water quality standards. These procedures require extensive studies involving sampling and monitoring of the waters around affected facilities. Each state may require changes in plant operations. We continually perform studies to determine whether any changes will be necessary to comply with these regulations. However, our newly developed or modified facilities are designed to meet the most stringent new requirements, thereby often minimizing the need for ongoing monitoring and extensive studies. Some of our facilities also are not covered by NPDES discharge permits due to alternative designs for handling wastewater. In fact, some of our facilities are designed as zero discharge facilities.

        Under current provisions of the Clean Water Act, existing permits must be renewed at least every five years, at which time permit limits come under extensive review and can be modified to account for more stringent regulations. In addition, the permits can be modified at any time. Some of our existing generating facilities' wastewater discharge permits, when renewed in the near future, may be subject to new regulations involving water intake systems. If such regulations are promulgated in a form similar to recently issued requirements for new facilities, significant costs could be incurred to renew the permits.

        In addition, changes to the environmental permits of our coal or other fuel suppliers due to federal or state initiatives may increase the cost of fuel, which in turn could have a significant impact on our operations.

Resource Conservation and Recovery Act

The EPA has regulations for implementing the portions of the Resource Conservation and Recovery Act that deal with the management of hazardous wastes. These regulations identify certain spent materials as hazardous wastes and establish standards and requirements for those who generate, transport, store, or dispose of such wastes. States have adopted regulations governing the management of hazardous wastes that are similar to the EPA regulations and in some cases more stringent. We have procedures in place to comply with all applicable EPA and state regulations governing the management of hazardous wastes. Some high volume generation facility wastes, such as coal fly ash and bottom ash, are exempt from these regulations federally, however in some states like California they are subject to more stringent rules and testing requirements. We currently use all of our

17

coal fly ash and bottom ash in a manner approved by federal, state, and local laws and regulations. These include the use of ash as structural fill material, recycled material that can be sold to the construction industry for a number of approved uses, and landfills. We continue to evaluate various recycling opportunities for our coal fly ash and bottom ash.

Comprehensive Environmental Response, Compensation and Liability Act (Superfund statute)

This law, or CERCLA, among other things, imposes cleanup requirements for threatened or actual releases of hazardous substances that may endanger public health or welfare of the environment. Under CERCLA, joint and several liability may be imposed on waste generators, site owners and operators and others regardless of fault or the legality of the original disposal activity. Many states have implemented laws similar to CERCLA. Although all waste substances generated by our facilities are generally not regarded as hazardous substances, some products used in the operations and the disposal of such products are governed by CERCLA and similar state statutes.

Metal Bank

In the early 1970s, BGE shipped an unknown number of scrapped transformers to Metal Bank of America, a metal reclaimer in Philadelphia. Metal Bank's scrap and storage yard has been found to be contaminated with oil containing high levels of PCBs (hazardous chemicals frequently used as a fire resistant coolant in electrical equipment). On December 7, 1987, the EPA notified BGE and nine other utilities that they are considered potentially responsible parties (PRPs) with respect to the cleanup of the site. BGE, along with the other PRPs, submitted a remedial investigation and feasibility study (RI/FS) to the EPA on October 14, 1994, and the EPA issued its Record of Decision (ROD) on December 31, 1997. On June 26, 1998, the EPA ordered BGE, the other utility PRPs, and the owner/operator to implement the requirements of the ROD. The utility PRPs are currently conducting the remedial design. Based on the ROD, BGE's share of the reasonably possible cleanup costs, estimated to be approximately 15.47%, could be as much as $2.3 million higher than amounts we have recorded as a liability on our Consolidated Balance Sheets.

Kane and Lombard Streets

Suit was originally filed by the EPA under CERCLA in October 1989 against BGE and several other defendants in the U.S. District Court for the District of Maryland, seeking to recover past and future clean up costs at the Kane and Lombard Street site located in Baltimore City, Maryland. The State of Maryland filed a similar complaint in the same case and court in February 1990. The complaints alleged that BGE arranged for coal fly ash to be deposited on the site. The Court dismissed these complaints in November 1995. Maryland began additional investigation on the remainder of the site for the EPA, but never completed the investigation. BGE, along with three other defendants, agreed to complete a remedial investigation/feasibility study of groundwater contamination around the site in a July 1993 consent order. The remedial investigation report and a draft feasibility study were submitted to the EPA in February 2002. While the EPA plans to select a remedy for this site in 2002, at this time we cannot estimate the total cost of the remedy or BGE's share of the site cleanup costs.

Drumco Drum Dump Site

In September 1996, BGE received an information request from EPA about the Drumco Drum Dump Site, located in the Curtis Bay area of Baltimore, Maryland. This site was the subject of an emergency drum removal action in 1991, due to a concern about hazardous substances leaking from drums and posing a threat to human health and the environment. According to EPA documents, approximately $2 million was spent on the drum removal action. To our knowledge, no long-term remediation is planned for this site. In addition, we understand that the EPA has sent information requests to approximately 17 other parties. BGE's records indicate that it sold empty drums to Drumco, Inc. from approximately 1983-1990. Although our potential liability cannot be estimated, we do not expect such liability to be material based on BGE's records showing that it sold only empty storage drums to Drumco, Inc.

68^th Street Dump

In July 1999, the EPA notified BGE, along with 19 other entities, that it may be a potentially responsible party at the 68^th Street Dump/Industrial Enterprises Site, also known as the Robb Tyler Dump, located in Baltimore, Maryland. The EPA indicated that it is proceeding with plans to conduct a remedial investigation and feasibility study. This site was proposed for listing as a federal Superfund site in January 1999, but the listing has not been finalized. Although our potential liability cannot be estimated, we do not expect such liability to be material based on BGE records showing that it did not send waste to the site.

Spring Gardens

In the early part of last century, predecessor gas companies (which were later merged into BGE) manufactured coal gas for residential and industrial use. The residue from this manufacturing process was coal tar, previously thought to be harmless but now found to contain a number of chemicals designated by the EPA as hazardous substances. BGE is coordinating an investigation of some of these former manufacturing sites, and determining what, if any, remedial action may

18

be required by the Maryland Department of the Environment (MDE).

        In late December 1996, BGE signed a consent order with the MDE that requires it to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. BGE submitted the required remedial action plans, and they have been approved by the MDE. Based on the remedial action plans, the costs BGE considers to be probable to remedy the contamination are estimated to total $47 million in nominal dollars (including inflation). BGE has recorded these costs as a liability on its Consolidated Balance Sheets and has deferred these costs, net of accumulated amortization and amounts it recovered from insurance companies, as a regulatory asset. BGE discusses this further in Note 6 to Consolidated Financial Statements. Through December 31, 2001, BGE has spent approximately $37 million for remediation at this site.

        BGE is also required by accounting rules to disclose additional costs it considers to be less likely than probable, but still "reasonably possible" of being incurred at these sites. Because of the results of studies at these sites, it is reasonably possible that these additional costs could exceed the amount BGE recognized by approximately $14 million in nominal dollars.

        As a result of CERCLA's no-fault, retroactive liability scheme, we cannot assure you that we will be free from substantial liabilities for other sites in the future.

Employees

Constellation Energy and its subsidiaries had, at December 31, 2001, approximately 9,200 employees, including 1,272 employees at Nine Mile Point. The Central Wayne plant has a partial unionized workforce where 29 employees are represented by the International Union of Operating Engineers. The labor contract with this union expires June 30, 2004. At the Nine Mile Point plant, employees are represented by the International Brotherhood of Electrical Workers, Local 97. The labor contract with this union expires in July 2006 with wages open to negotiation in July 2003. Our relations with both unions are good.

        We discuss several workforce reduction programs in more detail in Item 7. Management's Discussion and Analysis—Events of 2001 section.

Item 2. Properties

Constellation Energy's corporate offices occupy approximately 34,000 square feet of leased office space in Baltimore, Maryland. The corporate offices for most of our merchant energy business occupy approximately 97,000 square feet of leased office space in another building in Baltimore, Maryland. We describe our electric generation properties in the Merchant Energy Business section. We also have leases for other offices and services located in the Baltimore metropolitan region, and for various real property and facilities relating to our generation projects.

        We own BGE's principal headquarters building in downtown Baltimore. BGE owns the following propane air and liquefied natural gas facilities:

•

a liquefied natural gas facility for the liquefaction and storage of natural gas with a total storage capacity of 1,075,645 DTH and a planned daily capacity of 287,988 DTH, and

•

a propane air facility with a mined cavern with a total storage capacity of 545,000 DTH and a planned daily capacity of 85,000 DTH.

        BGE also has rights-of-way to maintain 26-inch natural gas mains across certain Baltimore City owned property (principally parks) which expire in 2004. These rights-of-way can be renewed during their last year for an additional period of 25 years based on a fair revaluation. Conditions of the grants are satisfactory.

        BGE has electric transmission and electric and gas distribution lines located:

•

in public streets and highways pursuant to franchises, and

•

on rights-of-way secured for the most part by grants from owners of the property.

All of BGE's property is subject to the lien of BGE's mortgage securing its mortgage bonds. All of the generation facilities transferred to affiliates by BGE on July 1, 2000, along with the stock we own in certain of our subsidiaries, are subject to the lien of BGE's mortgage.

        We believe we have satisfactory title to our project facilities in accordance with standards generally accepted in the energy industry, subject to exceptions which, in our opinion, would not have a material adverse effect on the use or value of the facilities.

        During 2002, we expect to replace and increase our corporate office space through a new lease in another building in Baltimore, Maryland. If we require additional space, we believe that we will be able to secure it on commercially reasonable terms without undue disruption to our operations.

Item 3. Legal Proceedings

We discuss our legal proceedings in Note 11 to Consolidated Financial Statements.

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Item 4. Submission of Matters to Vote of Security Holders

Not applicable.

Executive Officers of the Registrant

BGE meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K for a reduced disclosure format. Accordingly, the executive officers of BGE are not presented below.

        Executive Officers of Constellation Energy Group at the date of this report are:

Name	Age	Present Office	Other Offices or Positions Held During Past Five Years
Christian H. Poindexter	63	Chairman of the Board (A) (since formation of Constellation Energy Group as the holding company on April 30, 1999; since March 1, 1998 for BGE)	Chairman of the Board, President, and Chief Executive Officer—Constellation Energy and BGE.
Mayo A. Shattuck, III	47	President and Chief Executive Officer of Constellation Energy (A) (since November 1, 2001)	Co-Chairman and Co-Chief Executive Officer—DB Alex Brown, LLC and Deutsche Banc Securities, Inc., Vice Chairman—Bankers Trust Corporation, and President and Chief Operating Officer and Director—Alex Brown Inc.
E. Follin Smith	42	Senior Vice President and Chief Financial Officer of Constellation Energy and Baltimore Gas and Electric Company (since June 2001)	Senior Vice President and Chief Financial Officer—Armstrong Holdings, Inc.; Vice President and Treasurer—Armstrong Holdings, Inc. (filed for bankruptcy under Chapter 11 on December 6, 2000); and Chief Financial Officer—General Motors—Delphi Chassis Systems.
Michael J. Wallace	54	President of Constellation Generation Group (since January 2002)	Managing Director and Member—Barrington Energy Partners; and Senior Vice President—Commonwealth Edison.
Thomas V. Brooks	39	President of Constellation Power Source, Inc. (since October 2001)	Vice President of Business Development and Strategy—Constellation Energy and Vice President—Goldman Sachs.
Frank O. Heintz	58	President and Chief Executive Officer of Baltimore Gas and Electric Company (since July 1, 2000)	Executive Vice President, Utility Operations—BGE; and Vice President, Gas—BGE.
Thomas F. Brady	52	Vice President Corporate Strategy and Development (since formation of Constellation Energy Group as the holding company on April 30, 1999; since January 1, 1999 for BGE)	Vice President, Retail Services—BGE; and Vice President, Customer Service and Distribution—BGE.
David A. Brune	61	Vice President, General Counsel, and Secretary of Constellation Energy Group (since July 2001)	Vice President Finance and Accounting, Chief Financial Officer and Secretary—Constellation Energy Group and BGE; and General Counsel—BGE.

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Elaine W. Johnston	60	Vice President—Human Resources of Constellation Energy Group (since December 2001)	Managing Director Human Resources and Administration—Constellation Power Source Holdings, Inc.; Manager—Human Resources Services—Constellation Enterprises, Inc.; Manager—Staff Services—BGE; and Director of Benefits—BGE.
John R. Collins	44	Vice President and Chief Risk Officer of Constellation Energy Group (since December 2001)	Managing Director—Finance—Constellation Power Source Holdings, Inc.; and Treasurer and Assistant Secretary—Constellation Power Source, Inc.
Paul J. Allen	50	Vice President—Corporate Affairs of Constellation Energy Group (since May 2001)	Senior Vice President and Group Head—Ogilvy Public Relations.

(A)

Director and member of the Executive Committee.

Officers of Constellation Energy Group are elected by, and hold office at the will of, the Board of Directors and do not serve a "term of office" as such. There is no arrangement or understanding between any director or officer and any other person pursuant to which the director or officer was selected.

PART II

Item 5. Market for Registrant's Common Equity and Related Shareholder Matters

Stock Trading

Constellation Energy's common stock is traded under the ticker symbol CEG. It is listed on the New York, Chicago, and Pacific stock exchanges. It has unlisted trading privileges on the Boston, Cincinnati, and Philadelphia exchanges.

        As of March 22, 2002, there were 53,435 common shareholders of record.

Dividend Policy

Constellation Energy pays dividends on its common stock after its Board of Directors declares them. There is no limitation on Constellation Energy paying common stock dividends.

        BGE pays dividends on its common stock after its Board of Directors declares them. There is no limitation on BGE paying common stock dividends unless:

•

BGE elects to defer interest payments on the 7.16% Deferrable Interest Subordinated Debentures due June 30, 2038, and any deferred interest remains unpaid; or

•

all dividends (and any redemption payments) due on BGE's preference stock have not been paid.

        Dividends have been paid on the common stock continuously since 1910. Future dividends depend upon future earnings, our financial condition, and other factors.

        On January 30, 2002, we announced an increase in our quarterly dividend to 24 cents per share on our common stock payable April 1, 2002 to holders of record on March 11, 2002. This is equivalent to an annual rate of 96 cents per share.

        Quarterly dividends were declared on the common stock during 2001 and 2000 in the amounts set forth below.

Common Stock Dividends and Price Ranges

		2001						2000
				Price*						Price*
		Dividend Declared						Dividend Declared
				High		Low				High		Low
First Quarter		$	.12	$	44.65	$	34.69	$	.42	$	33.81	$	27.06
Second Quarter			.12		50.14		40.10		.42		35.69		31.25
Third Quarter			.12		43.80		22.85		.42		52.06		32.06
Fourth Quarter			.12		28.21		20.90		.42		50.50		37.88
	Total	$	.48					$	1.68

* Based on New York Stock Exchange Composite Transactions as reported in THE WALL STREET JOURNAL.

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Item 6. Selected Financial Data

Constellation Energy Group, Inc. and Subsidiaries

			2001		2000		1999			1998		1997
			(Dollar amounts in millions, except per share amounts)
Summary of Operations
	Total Revenues		$	3,928.3	$	3,852.5	$	3,840.9		$	3,386.4	$	3,307.6
	Total Expenses			3,570.5		3,009.9		3,081.0			2,647.9		2,584.0
	Income From Operations			357.8		842.6		759.9			738.5		723.6
	Other Income (Expense)			1.3		4.2		7.9			5.7		(52.8	)
	Income Before Fixed Charges and Income Taxes			359.1		846.8		767.8			744.2		670.8
	Fixed Charges			238.8		271.4		255.0			260.6		258.7
	Income Before Income Taxes			120.3		575.4		512.8			483.6		412.1
	Income Taxes			37.9		230.1		186.4			177.7		158.0
	Income Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle			82.4		345.3		326.4			305.9		254.1
	Extraordinary Loss, Net of Income Taxes			—		—		(66.3	)		—		—
	Cumulative Effect of Change in Accounting Principle, Net of Income Taxes			8.5		—		—			—		—
	Net Income		$	90.9	$	345.3	$	260.1		$	305.9	$	254.1
	Earnings Per Common Share and
		Earnings Per Common Share — Assuming Dilution Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle	$	.52	$	2.30	$	2.18		$	2.06	$	1.72
	Extraordinary Loss			—		—		(.44	)		—		—
	Cumulative Effect of Change in Accounting Principle			.05		—		—			—		—
	Earnings Per Common Share and
		Earnings Per Common Share — Assuming Dilution	$	.57	$	2.30	$	1.74		$	2.06	$	1.72
	Dividends Declared Per Common Share		$	.48	$	1.68	$	1.68		$	1.67	$	1.63
Summary of Financial Condition
	Total Assets		$	14,077.6	$	12,939.3	$	9,745.1		$	9,434.1	$	8,900.0
	Short-Term Borrowings		$	975.0	$	243.6	$	371.5		$	—	$	316.1
	Current Portion of Long-Term Debt		$	1,406.7	$	906.6	$	808.3		$	541.7	$	271.9
	Capitalization
		Long-Term Debt	$	2,712.5	$	3,159.3	$	2,575.4		$	3,128.1	$	2,988.9
		Redeemable Preference Stock		—		—		—			—		90.0
		Preference Stock Not Subject to Mandatory Redemption		190.0		190.0		190.0			190.0		210.0
		Common Shareholders' Equity		3,843.6		3,174.0		3,017.5			2,995.9		2,876.4
	Total Capitalization		$	6,746.1	$	6,523.3	$	5,782.9		$	6,314.0	$	6,165.3
Financial Statistics at Year End
	Ratio of Earnings to Fixed Charges			1.18		2.78		2.87			2.60		2.35
	Book Value Per Share of Common Stock		$	23.48	$	21.09	$	20.17		$	20.08	$	19.47

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

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Baltimore Gas and Electric Company and Subsidiaries

			2001		2000		1999			1998		1997
			(Dollar amounts in millions, except per share amounts)
Summary of Operations
	Total Revenues		$	2,720.7	$	2,746.8	$	3,092.2		$	3,386.4	$	3,307.6
	Total Expenses			2,408.9		2,334.4		2,387.9			2,647.9		2,584.0
	Income From Operations			311.8		412.4		704.3			738.5		723.6
	Other Income (Expense)			0.4		7.5		8.4			5.7		(52.8	)
	Income Before Fixed Charges and Income Taxes			312.2		419.9		712.7			744.2		670.8
	Fixed Charges			154.6		184.0		205.9			238.8		230.0
	Income Before Income Taxes			157.6		235.9		506.8			505.4		440.8
	Income Taxes			60.3		92.4		178.4			177.7		158.0
	Income Before Extraordinary Item			97.3		143.5		328.4			327.7		282.8
	Extraordinary Loss, Net of Income Taxes			—		—		(66.3	)		—		—
	Net Income			97.3		143.5		262.1			327.7		282.8
	Preference Stock Dividends			13.2		13.2		13.5			21.8		28.7
	Earnings Applicable to Common Stock		$	84.1	$	130.3	$	248.6		$	305.9	$	254.1
Summary of Financial Condition
	Total Assets		$	4,954.5	$	4,654.2	$	7,272.6		$	9,434.1	$	8,900.0
	Short-Term Borrowings		$	—	$	32.1	$	129.0		$	—	$	316.1
	Current Portion of Long-Term Debt and Preference Stock		$	666.3	$	567.6	$	523.9		$	541.7	$	271.9
	Capitalization
		Long-Term Debt	$	1,821.7	$	1,864.4	$	2,206.0		$	3,128.1	$	2,988.9
		Redeemable Preference Stock		—		—		—			—		90.0
		Preference Stock Not Subject to Mandatory Redemption		190.0		190.0		190.0			190.0		210.0
		Common Shareholders' Equity		1,131.4		802.3		2,355.4			2,981.5		2,870.4
	Total Capitalization		$	3,143.1	$	2,856.7	$	4,751.4		$	6,299.6	$	6,159.3
Financial Statistics at Year End
	Ratio of Earnings to Fixed Charges			1.99		2.27		3.45			2.94		2.78
	Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends			1.75		2.03		3.14			2.60		2.35

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

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

Introduction

Constellation Energy Group, Inc. (Constellation Energy) is a North American energy company that conducts its business through various subsidiaries including a merchant energy business and Baltimore Gas and Electric Company (BGE). Our merchant energy business generates and markets wholesale electricity in North America. BGE is an electric and gas public utility company with a service territory that covers the City of Baltimore and all or part of ten counties in central Maryland. We describe our operating segments in Note 3.

        This report is a combined report of Constellation Energy and BGE. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "utility business" are to BGE.

        Effective July 1, 2000, electric generation was deregulated in Maryland. Also, on July 1, 2000, BGE transferred all of its generation assets and related liabilities at book value to our merchant energy business. As a result, the financial results of the electric generation portion of our business are included in the merchant energy business beginning July 1, 2000. Prior to July 1, 2000, the financial results of electric generation were included in BGE's regulated electric business. We discuss the deregulation of electric generation in the Business Environment section.

        Our merchant energy business includes:

•

fossil, nuclear, and hydroelectric generating facilities, interests in domestic power projects, and nuclear consulting services, and

•

power marketing, origination transactions, and risk management services.

        BGE is a regulated electric and gas public transmission and distribution utility company.

        Our other nonregulated businesses include:

•

energy products and services,

•

home products, commercial building systems, and residential and commercial electric and gas retail marketing,

•

a general partnership, in which BGE is a partner, that provides cooling services for commercial customers in Baltimore,

•

financial investments,

•

real estate and senior-living facilities, and

•

interests in Latin American power generation and distribution projects and investments.

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

•

what factors affect our businesses,

•

what our earnings and costs were in the years presented,

•

why earnings and costs changed between years,

•

where our earnings came from,

•

how all of this affects our overall financial condition,

•

what our expenditures for capital projects were for 1999 through 2001, and what we expect them to be through 2003, and

•

where we expect to get cash for future capital expenditures.

        As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2001, 2000, and 1999. We analyze and explain the differences between periods in the specific line items of the Consolidated Statements of Income.

        Also, this discussion and analysis is based on the operation of the electric generation portion of our utility business under rate regulation through June 30, 2000. Our regulated electric business changed as we transferred our electric generation assets and related liabilities to our merchant energy business, and we entered into retail customer choice for electric generation effective July 1, 2000. Accordingly, the results of operations and financial condition described in this discussion and analysis are not necessarily indicative of future performance.

Critical Accounting Policies

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

•

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

•

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

•

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

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

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

        Management believes the following accounting policies require us to use more significant judgments and estimates in preparing our financial statements and could represent critical accounting policies as defined by the SEC. We discuss our significant accounting policies, including those that do not require management to make difficult, subjective, or complex judgments or estimates, in Note 1.

Revenue Recognition/Mark-to-Market Method of Accounting

Our subsidiary, Constellation Power Source, uses the mark-to-market method of accounting to account for a portion of its power marketing activities. We record all other revenues in

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the period earned for services rendered, commodities or products delivered, or contracts settled.

        Power marketing activities include new origination transactions and risk management activities using contracts for energy, other energy-related commodities, and related derivative contracts. We use the mark-to-market method of accounting for portions of Constellation Power Source's activities as required by EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. Under the mark-to-market method of accounting, we record the fair value of commodity and derivative contracts as mark-to-market energy assets and liabilities at the time of contract execution. We record reserves to reflect uncertainties associated with certain estimates inherent in the determination of fair value. Mark-to-market energy revenues include:

•

the fair value of new transactions at origination,

•

unrealized gains and losses from changes in the fair value of open positions,

•

net gains and losses from realized transactions, and

•

changes in reserves.

        We record the changes in mark-to-market energy assets and liabilities on a net basis in "Nonregulated revenues" in our Consolidated Statements of Income. Mark-to-market energy assets and liabilities are comprised of a combination of energy and energy-related derivative and non-derivative contracts. While some of these contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using modeling techniques to determine expected future market prices, contract quantities, or both. The market prices used to determine fair value reflect management's best estimate considering various factors, including closing exchange and over-the-counter quotations, time value, and volatility factors. However, it is possible that future market prices could vary from those used in recording mark-to-market energy assets and liabilities, and such variations could be material.

        Certain power marketing and risk management transactions entered into under master agreements and other arrangements provide our merchant energy business with a right of setoff in the event of bankruptcy or default by the counterparty. We report such transactions net in the balance sheets in accordance with FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts.

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

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

We are required to evaluate certain assets that have long lives (generating property and equipment and real estate) to determine if they are impaired if certain conditions exist. We determine if long-lived assets are impaired by comparing their undiscounted expected future cash flows to their carrying amount in our accounting records. We would record an impairment loss if the undiscounted expected future cash flows from an asset were less than the carrying amount of the asset. Additionally, we evaluate our equity-method investments to determine whether they have experienced a loss in value that is considered other than a temporary decline in value.

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

Events of 2001

In the past year, the utility industry and energy markets experienced significant changes as a result of the slowing of the U.S. economy, the significant declines in both the short-term and long-term market prices of electricity in certain regions, the events in California, the financial collapse of Enron Corporation (Enron), as well as the effects of the September 11, 2001 terrorist attacks, and the threat of additional attacks. We address certain of these issues in the Business Environment section.

        In response to our changing business environment, we canceled our separation plans and terminated our power business services agreement with Goldman Sachs & Co. (Goldman Sachs) on October 26, 2001. We believe that maintaining our current corporate structure provides a better platform of size, strength, and stability from which to execute our strategies. As a result of the significant declines in market prices of electricity, we terminated all planned development projects not currently under construction.

        Separately, we initiated efforts to reduce costs in order to become more competitive and to sell certain non-core assets in order to focus management's attention and our capital resources on our core energy businesses. We discuss our initiatives in more detail in this section. We continue to examine plans to achieve our strategies, and to further strengthen our balance sheet and enhance our liquidity.

Contract Termination Related Costs

We announced the termination of our power business services agreement with Goldman Sachs. We paid Goldman Sachs a total of $355 million, representing $196 million to terminate the power business services agreement with our power marketing operation and $159 million previously recognized as a payable for services rendered under the agreement. We issued commercial paper and borrowed under our existing bank lines to fund this payment. In the fourth quarter of 2001, we recognized expenses of approximately $224.8 million pre-tax, or $139.6 million after-tax, related to the termination of the contract with Goldman Sachs. Goldman Sachs also will not make an equity investment in our merchant energy business as previously announced. We discuss the termination of our power business services agreement with Goldman Sachs in Note 2.

Sale of Guatemalan Operations

On November 8, 2001, we sold our Guatemalan power plant operations to an affiliate of Duke Energy International, L.L.C., the international business unit of Duke Energy. Through this sale, Duke Energy acquired Grupo Generador de Guatemala y

25

Cia., S.C.A., which owns two generating plants at Esquintla and Lake Amatitlan in Guatemala. The combined capacity of the plants is 167 megawatts.

        We decided to sell our Guatemalan operations to focus our efforts on our core energy businesses. As a result of this transaction, we are no longer committed to making significant future capital investments in this non-core operation. We recorded a pre-tax loss of $43.3 million, or $28.1 million after-tax, in the fourth quarter of 2001, resulting from this sale. We discuss this sale in Note 2.

Workforce Reduction Programs

In the fourth quarter of 2001, we undertook several measures to reduce our workforce through both voluntary and involuntary means. The purpose of these programs was to reduce our operating costs to become more competitive. As part of this initiative, several companies including our merchant energy business and BGE announced Voluntary Special Early Retirement Programs (VSERP) to provide enhanced retirement benefits to certain eligible participants that elect to retire in 2002 and other involuntary severance programs.

        As a result, we recorded $105.7 million pre-tax, or $64.1 million after-tax, of expenses related to these programs during the fourth quarter of 2001. BGE recorded $57.0 million of the pre-tax amount as expense relating to its electric and gas businesses. BGE also recorded $19.5 million on its balance sheet as a regulatory asset of its gas business. We will continue cost-cutting measures to remain competitive in our business environment and expect to record approximately $35 million of additional expense in 2002 related to the programs implemented to date. As a result of our workforce reduction efforts to date, we expect annual cost savings of approximately $72 million.

        We also expect that a significant number of retiring employees covered by our qualified, basic pension plan will elect to receive their pension benefit in the form of a lump-sum payment in 2002. These lump-sum payments may exceed annual plan service cost and interest expense that could trigger a settlement loss in 2002 estimated to be approximately $20 million.

        We discuss our early retirement and severance programs in more detail in Note 2, Note 6, and Note 7.

Impairment Losses and Other Costs

In the fourth quarter of 2001, our merchant energy business recorded impairments of $46.9 million pre-tax, or $30.5 million after-tax, primarily due to the termination of all planned development projects not currently under construction, including projects in Texas, California, Florida, and Massachusetts and due to a decline in value of an investment in a power project in Michigan. We decided to terminate our development projects due to the expected excess generation capacity in most domestic markets and the significant decline in the forward market prices of electricity. The impairments include costs associated with four turbines no longer expected to be placed in service.

        In the fourth quarter of 2001, our other nonregulated businesses recorded $107.3 million pre-tax, or $69.7 million after-tax, in impairments of certain non-core assets as follows:

•

We decided to sell six real estate projects without further development and our senior-living facilities and accelerate the exit strategies for two other real estate projects that we will continue to hold and own over the next several years.

•

We decided to accelerate the exit strategy for the investment in a distribution company in Panama.

•

There was an other than temporary decline in value in our equity method Bolivian investment due to a deterioration in our investment's position in the Bolivian capacity market.

        In addition, our financial investments business recorded a $4.6 million pre-tax, or $2.8 million after-tax, reduction of its investment in an aircraft due to the decline in value of used airplanes as a result of the September 11, 2001 terrorist attacks and the general downturn in the aviation industry.

        We discuss these special costs further in Note 2.

Acquisition of Nine Mile Point

On November 7, 2001, we completed our purchase of the Nine Mile Point Nuclear Station (Nine Mile Point) located in Scriba, New York. Nine Mile Point Nuclear Station, LLC, a subsidiary of Constellation Nuclear, purchased 100 percent of Nine Mile Point Unit 1 and 82 percent of Unit 2 for cash of $382.7 million including settlement costs and a sellers' note of $388.1 million to be repaid over five years with an interest rate of 11.0%. This note may be prepaid at any time without penalty. The sellers also transferred approximately $442 million in decommissioning funds. As a result of this purchase, we own 1,550 megawatts of Nine Mile Point's 1,757 megawatts of total generating capacity.

        We will sell 90% of our share of Nine Mile Point's output, on a unit contingent basis (if the output is not available because the plant is not operating, there is no requirement to provide output from other sources), back to the sellers at an average price of nearly $35 per megawatt-hour for approximately 10 years under power purchase agreements.

        We discuss the acquisition of Nine Mile Point further in Note 14.

Enron

On December 2, 2001, Enron Corporation filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Our financial exposure to Enron is not material. Prior to the bankruptcy filing, our power marketing operation settled its positions with Enron and as a result has no direct credit exposure to Enron.

Bethlehem Steel

On October 15, 2001, Bethlehem Steel Corporation filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Bethlehem Steel's Sparrows Point plant, located in Baltimore, Maryland is BGE's largest customer, accounting for approximately three percent of electric revenues and one percent

26

of gas revenues. At December 31, 2001, our exposure to Bethlehem Steel was not material. There is uncertainty regarding the continuation of Bethlehem Steel's operations; however, we do not expect the impact to be material to our financial results.

New President and Chief Executive Officer

Effective November 1, 2001, Mayo A. Shattuck, III was elected President and Chief Executive Officer of Constellation Energy. Christian H. Poindexter remains as Chairman of the Board. Mr. Shattuck has been a Director of Constellation Energy or a subsidiary for seven years. Prior to joining Constellation Energy, he was Global Head of Investment Banking for Deutsche Bank and Co-Chairman and Co-Chief Executive Officer of DB Alex. Brown and Deutsche Bank Securities.

Certain Relationships

Michael J. Wallace, prior to becoming President of Constellation Generation Group on January 1, 2002, was a Managing Member and Managing Director and greater than 10% owner of Barrington Energy Partners, LLC. Upon becoming President of Constellation Generation Group, Mr. Wallace terminated his affiliation with Barrington, and no longer holds any ownership interest in it. Barrington Energy Partners provided consulting services to Constellation Energy and its subsidiary, Constellation Nuclear during 2001, and is continuing to do so during 2002. We paid Barrington approximately $4.4 million in 2001.

Events of 2002

Dividend Increase

On January 30, 2002, we announced an increase in our quarterly dividend to 24 cents per share on our common stock payable April 1, 2002 to holders of record on March 11, 2002. This is equivalent to an annual rate of 96 cents per share. Previously, our quarterly dividend on our common stock was 12 cents per share, equivalent to an annual rate of 48 cents per share.

Investment in Orion

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

Investment in Corporate Office Properties Trust (COPT)

In March 2002, we sold all of our COPT equity-method investment, approximately 8.9 million shares, as part of a public offering. We received cash proceeds of $101.3 million on the sale, which approximates the book value of our investment.

Strategy

On October 26, 2001, we announced the decision to remain a single company and canceled prior plans to separate our merchant energy business from our other businesses and terminated our power business services agreement with Goldman Sachs as previously discussed in the Events of 2001 section.

        Our primary growth strategy centers on our merchant energy business. The strategy for our merchant energy business is to be a leading competitive provider of energy solutions for wholesale customers in North America. Our merchant energy business has electric generation assets located in various regions of the United States and engages in power marketing and risk management activities and provides energy solutions to meet wholesale customers' needs throughout North America.

        Our merchant energy business integrates electric generation assets with power marketing and risk management of energy and energy-related commodities. This integration allows our merchant energy business to maximize value across energy products, over geographic regions, and over time. Our power marketing operation adds value to our generation assets by providing national market access, market infrastructure, real-time market intelligence, risk management and arbitrage opportunities, and transmission and transportation expertise. Generation capacity supports our power marketing operation by providing a source of reliable power supply, enhancing our ability to structure sophisticated products and services for customers, building customer credibility, and providing a physical hedge.

        Currently, our merchant energy business controls over 11,500 megawatts of generation including the 1,550 megawatts of the nuclear generating capacity at Nine Mile Point and the 1,100 megawatts of natural gas-fired peaking capacity that commenced operations in the Mid-Atlantic and Mid-West regions during mid-summer 2001. We also have approximately 2,900 megawatts of natural gas-fired peaking and combined cycle production facilities under construction in Texas, California, Florida, and Illinois.

        To achieve our strategic objectives, we expect to continue to support our power marketing and risk management operations with generation assets that have diversified geographic, fuel, and dispatch characteristics. We also expect to use a disciplined growth strategy through originating transactions with wholesale customers and by acquiring and developing additional generating facilities when necessary to support our power marketing operation.

        Our merchant energy business will focus on long-term, high-value sales of energy, capacity, and related products to distribution companies and other wholesale purchasers, primarily in the regional markets in which end user electricity rates have been deregulated and thereby separated from the cost of generation supply. These markets include the Northeast region, the Mid-Atlantic region, and Texas.

        The growth of BGE and our retail energy services businesses is expected through focused and disciplined expansion.

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

        In the fourth quarter of 2001, we undertook a number of initiatives to reduce our costs towards competitive levels and to

27

ensure that our management and capital resources are focused on our core energy businesses. This included the implementation of workforce reduction programs, efforts to reduce capital spending for planned development projects not currently under construction, and to accelerate our exit strategy for certain non-core assets.

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

•

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

•

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

•

sale of assets or one or more businesses.

Business Environment

With the shift toward customer choice, competition, and the growth of our merchant energy business, various factors will affect our financial results in the future. We discuss these various factors in the Forward Looking Statements section.

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

Electric Competition

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

Maryland

On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition Act of 1999 (the Act) and accompanying tax legislation that significantly restructured Maryland's electric utility industry and modified the industry's tax structure.

        In the Restructuring Order discussed below, the Maryland PSC addressed the major provisions of the Act. The accompanying tax legislation is discussed in detail in Note 5.

        On November 10, 1999, the Maryland PSC issued a Restructuring Order that resolved the major issues surrounding electric restructuring, accelerated the timetable for customer choice, and addressed the major provisions of the Act. The Restructuring Order also resolved the electric restructuring proceeding (transition costs, customer price protections, and unbundled rates for electric services) and a petition filed in September 1998 by the Office of People's Counsel (OPC) to lower our electric base rates. The major provisions of the Restructuring Order are discussed in Note 5.

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

•

All customers can choose their electric energy supplier. BGE will provide a standard offer service for customers that do not select an alternative supplier. In either case, BGE will continue to deliver electricity to all customers in areas traditionally served by BGE.

•

BGE reduced residential base rates by approximately 6.5%, on average about $54 million a year. These rates will not change before July 2006.

•

BGE transferred, at book value, its nuclear generating assets, its nuclear decommissioning trust fund, and related liabilities to Calvert Cliffs Nuclear Power Plant, Inc. In addition, BGE transferred, at book value, its fossil generating assets and related liabilities and its partial ownership interest in two coal plants and a hydroelectric plant located in Pennsylvania to Constellation Power Source Generation. In total, these generating assets represent about 6,240 megawatts of generation capacity with a total net book value at June 30, 2000 of approximately $2.4 billion.

•

BGE assigned approximately $47 million to Calvert Cliffs Nuclear Power Plant, Inc. and $231 million to Constellation Power Source Generation of tax-exempt debt related to the transferred assets.

•

Constellation Power Source Generation issued approximately $366 million in unsecured promissory notes to BGE. All of these notes have been repaid by Constellation Power Source Generation. The proceeds were used to service the current maturities of certain BGE long-term debt.

•

BGE transferred equity associated with the generating assets to Calvert Cliffs Nuclear Power Plant, Inc. and Constellation Power Source Generation.

•

The fossil fuel and nuclear fuel inventories, materials and supplies, and certain purchased power contracts of BGE were also assumed by these subsidiaries.

        Effective July 1, 2000, BGE provides standard offer service to customers at fixed rates over various time periods during the transition period (July 1, 2000 to June 30, 2006) for those customers that do not choose an alternate supplier. In addition, the electric fuel rate was discontinued effective July 1, 2000. Pursuant to the Restructuring Order, Constellation Power Source provides BGE with the energy and capacity required to meet its standard offer service obligations for the first three years of the transition period (July 1, 2000 to June 30, 2003).

        In August 2001, following a competitive bidding process, BGE entered into contracts with Constellation Power Source to provide 90% and Allegheny Energy Supply Company, LLC to provide the remaining 10% of the energy and capacity required for BGE to meet its standard offer service requirements for the final three years (July 1, 2003 to June 30, 2006) of the transition period. BGE awarded these contracts primarily based on price and access to the PJM region. The amount BGE pays for energy and capacity does not exceed the standard offer service rates received from customers. Over the transition period, the standard offer service rate that BGE receives from its customers increases. This is offset by a corresponding decrease in the competitive transition charge BGE receives.

        Constellation Power Source obtains the energy and capacity to supply BGE's standard offer service obligations from nonregulated affiliates that own Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) and BGE's former fossil plants, supplemented with energy and capacity purchased from the wholesale market if necessary.

Other States

Several states, other than Maryland, have supported complete deregulation of the electric industry. Other states that were

28

considering deregulation have slowed their plans or postponed consideration. While our power marketing operation may be affected by the slow down in deregulation, the Federal Energy Regulatory Commission (FERC) initiatives regarding the formation of larger Regional Transmission Organizations could provide our merchant energy business other opportunities as discussed in the FERC Regulation—Regional Transmission Organizations section.

        Our merchant energy business has $296.4 million invested in operating power projects of which our ownership percentage represents 146 megawatts of electricity that are sold to Pacific Gas & Electric (PGE) and to Southern California Edison (SCE) in California under power purchase agreements as discussed in the California Power Purchase Agreements section. Our merchant energy business was not paid in full for its sales from these plants to the two utilities from November 2000 through early April 2001. At December 31, 2001, our portion of the amount due for unpaid power sales from these utilities was approximately $45 million. We recorded reserves of approximately 20% of this amount.

        These projects entered into agreements with PGE and SCE that provide for five-year fixed-price payments averaging $53.70 per megawatt-hour plus the stated capacity payments in the original Interim Standard Offer No. 4 (SO4) contracts. These agreements also provide for the payment of all past due amounts plus interest. As of the date of this report, we have received $28 million related to the $45 million of unpaid power sales, of which 100% of the SCE outstanding balance was paid. We expect to collect the remaining outstanding balance from PGE within the next year.

        However, as a result of ongoing litigation before the FERC regarding sales into the spot markets of the California Independent System Operator (ISO) and Power Exchange, we may be required to pay refunds of between $3 and $4 million for transactions that we entered into with these entities for the period between October 2000 and June 2001. While the process at FERC is ongoing, FERC has indicated that we will have the ability to reduce the potential refund amount in order to recover outstanding receivables we are owed. FERC also has indicated that it will consider adjustments to the refund amount to the extent we can demonstrate that its refund methodology resulted in an overall revenue shortfall for our transactions in these markets during the refund period.

        The situation with PGE and SCE has not had a material impact on our financial results. However, we cannot provide any assurance that the events in California will not have a material, adverse impact on our financial results, or that any legislative, regulatory, or other solution enacted in California will permit us to recover any past losses or will not have a negative effect on our business opportunities in California.

        We are currently leasing and supervising the construction of the High Desert project, a 750 megawatt generating facility in California. The High Desert project uses an off-balance sheet financing structure through a special-purpose entity (SPE) that currently qualifies as an operating lease. The project is scheduled for completion in the summer of 2003. We signed a contract to sell all of the plant's output to the California Department of Water Resources on a unit contingent basis. The contract has a term of eight years and three months.

        In February 2002, the FASB proposed a new accounting interpretation that potentially would impact the accounting for, but not the cash flows associated with, our High Desert operating lease and the related SPE. Under the proposed interpretation, we may be required to consolidate the SPE in our Consolidated Balance Sheets. We would have recorded approximately $221 million of development, construction, and capitalized financing costs as an asset and the related financial obligations as a liability in our Consolidated Balance Sheets had we consolidated this project at December 31, 2001.

        We discuss our High Desert project in more detail in the Capital Resources section.

        In February 2002, the California Department of Water Resources filed a claim with the FERC that all long-term contracts for power supply that the California Department of Water Resources entered into in the first quarter of 2001, which includes the contracts related to our High Desert project, were not just and reasonable. The California Department of Water Resources is requesting the FERC to terminate the contracts entirely or, at least, modify the prices to terms that the FERC considers just and reasonable. Currently, we are discussing the renegotiations of our contracts with the California Department of Water Resources. We cannot estimate the timing or impact of the FERC proceedings or the renegotiations of our contracts.

Gas Competition

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

Market Risks

The decline in both short-term and long-term market prices of electricity has had, and is expected to continue to have, a significant, negative impact on our financial results in certain regions in which we operate or expect to operate. In addition, significant uncertainties exist in the competitive energy marketplace.

        We discuss our market risks in detail in Item 7. Management's Discussion and Analysis—Market Risk section.

Regulation by the Maryland PSC

In addition to electric restructuring which was discussed earlier, regulation by the Maryland PSC influences BGE's businesses.

        Under traditional rate regulation that continues after July 1, 2000 for BGE's electric transmission and distribution, and gas businesses, the Maryland PSC determines the rates we can charge our customers. Prior to July 1, 2000, BGE's regulated electric rates consisted primarily of a "base rate" and a "fuel rate." Effective July 1, 2000, BGE discontinued its electric fuel rate and unbundled its rates to show separate components for delivery service, competitive transition charges, standard offer services (generation), transmission, universal service, and taxes. The rates for BGE's regulated gas business continue to consist of a "base rate" and a "fuel rate."

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Base Rate

The base rate is the rate the Maryland PSC allows BGE to charge its customers for the cost of providing them service, plus a profit. BGE has both an electric base rate and a gas base rate. Higher electric base rates apply during the summer when the demand for electricity is higher. Gas base rates are not affected by seasonal changes.

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

        On June 19, 2000, the Maryland PSC authorized a $6.4 million annual increase in our gas base rates effective June 22, 2000.

        As a result of the Restructuring Order, BGE's residential electric base rates are frozen until 2006. Electric delivery service rates are frozen until 2004 for commercial and industrial customers. The generation and transmission components of rates are frozen for different time periods depending on the service options selected by those customers.

Fuel Rate

Through June 30, 2000, we charged our electric customers separately for the fuel we used to generate electricity (nuclear fuel, coal, gas, or oil) and for the net cost of purchases and sales of electricity. We charged the actual cost of these items to the customer with no profit to us. If these fuel costs went up, the Maryland PSC generally permitted us to increase the fuel rate.

        Under the Restructuring Order, BGE's electric fuel rate was frozen until July 1, 2000, at which time the fuel rate clause was discontinued. We deferred the difference between our actual costs of fuel and energy and what we collected from customers under the fuel rate through June 30, 2000.

        In September 2000, the Maryland PSC approved the collection of the $54.6 million accumulated difference between our actual costs of fuel and energy and the amounts collected from customers that were deferred under the electric fuel rate clause through June 30, 2000. We collected this accumulated difference from customers over the twelve-month period ended October 2001. Effective July 1, 2000, our earnings are affected by the changes in the cost of fuel and energy.

        We charge our gas customers separately for the natural gas they purchase from us. The price we charge for the natural gas is based on a market-based rates incentive mechanism approved by the Maryland PSC. We discuss market-based rates in more detail in the Gas Cost Adjustments section and in Note 1.

FERC Regulation—Regional Transmission Organizations

In December 1999, FERC issued Order 2000, amending its regulations under the Federal Power Act to advance the formation of Regional Transmission Organizations (RTOs).

        On July 12, 2001, FERC provisionally granted RTO status to PJM and ordered it to engage in mediation with the New York ISO and the New England ISO to create a business plan to form one Northeast RTO, using PJM as a platform. After further hearings by FERC, it announced that it is re-evaluating its Order regarding a Northeast RTO. In the meantime, PJM is exploring opportunities to expand into other regions.

        The creation of large RTOs could benefit our merchant energy business by allowing easier access to transmission and a uniform rate across various regions.

        In addition, PJM is required to submit a filing by July 1, 2002 addressing implementation of a uniform transmission rate by January 1, 2003. A uniform rate could expose BGE to higher transmission rates.

        BGE, jointly with other PJM transmission owners, requested rehearing and clarification from FERC on its July 12, 2001 order regarding certain incentive rates, interconnection procedures, and allocations of interconnection costs. FERC has not yet issued an order on this request.

Weather

Merchant Energy Business

Weather conditions in the different regions of North America influence the financial results of our merchant energy business. Weather conditions can affect the supply of and demand for electricity and fuels, and changes in energy supply and demand may impact the price of these energy commodities in both the spot market and the forward market. Typically, demand for electricity and its price are higher in the summer and the winter, when weather is more extreme. Similarly, the demand for and price of natural gas and oil are higher in the winter. However, all regions of North America typically do not experience extreme weather conditions at the same time. We discuss our market risk in detail in Item 7. Management's Discussion and Analysis—Market Risk section.

BGE

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

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

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

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

30

colder weather is measured by more heating degree days and results in greater demand for electricity and gas to operate heating systems.

        We show the number of cooling and heating degree days in 2001 and 2000, the percentage change in the number of degree days from the prior year, and the number of degree days in a "normal" year as represented by the 30-year average in the following table.

	2001		2000		30-year Average
Cooling degree days	787		736		839
Percentage change from prior year	6.9	%	(12.9	)%
Heating degree days	4,514		4,936		4,725
Percentage change from prior year	(8.5	)%	7.7	%

Other Factors

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

        The number of customers in a given period is affected by new home and apartment construction and by the number of businesses in our service territory. Under the Restructuring Order, BGE's electric customers can become delivery service customers only and can purchase their electricity from other sources. We will collect a delivery service charge to recover the fixed costs for the service we provide. The remaining electric customers will receive standard offer service from BGE at the fixed rates provided by the Restructuring Order. Usage per customer refers to all other items impacting customer sales that cannot be measured separately. These factors include the strength of the economy in our service territory. When the economy is healthy and expanding, customers tend to consume more electricity and gas. Conversely, during an economic downtrend, our customers tend to consume less electricity and gas.

Environmental and Legal Matters

You will find details of our environmental matters in Note 11 and Item 1. Business—Environmental Matters. You will find details of our legal matters in Note 11. Some of the information is about costs that may be material to our financial results.

Accounting Standards Adopted and Issued

We discuss recently adopted and issued accounting standards in Note 1.

Results of Operations

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

Overview

Net Income

		2001			2000			1999
		(In millions)
Net Income Before Special Costs Included in Operations:
Merchant energy		$	291.2		$	213.6		$	66.6
Regulated electric			84.5			106.5			270.0
Regulated gas			38.3			30.6			33.0
Other nonregulated			3.2			13.8			2.2
Net Income Before Special Costs Included in Operations			417.2			364.5			371.8
Special Costs Included in Operations:
	Contract termination related costs		(139.6	)		—			—
	Loss on sale of Guatemalan operations		(28.1	)		—			—
	Workforce reduction costs		(64.1	)		(4.2	)		—
	Impairments of domestic power projects		(30.5	)		—			(14.2	)
	Impairments of real estate, senior-living, and international investments		(69.7	)		—			(10.3	)
	Reduction of financial investments		(2.8	)		—			(16.0	)
	Deregulation transition cost		—			(15.0	)		—
	Hurricane Floyd		—			—			(4.9	)
Net Income Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle			82.4			345.3			326.4
Extraordinary Loss			—			—			(66.3	)
Cumulative Effect of Change in Accounting Principle			8.5			—			—
Net Income		$	90.9		$	345.3		$	260.1

Net income for the periods presented reflect a significant shift from the regulated electric business to the merchant energy business as a result of the transfer of BGE's electric generation assets to nonregulated subsidiaries on July 1, 2000. We discuss this in more detail in Note 5.

2001

Our total net income for 2001 decreased $254.4 million, or $1.73 per share, compared to 2000 mostly because of the following special costs in operations:

•

Our merchant energy business recorded expenses of $139.6 million after-tax, or $.87 per share, related to the termination of our power marketing operation's power business services agreement with Goldman Sachs.

•

Our Latin American operation recognized a $28.1 million after-tax, or $.17 per share, loss on the sale of the Guatemalan power plant operations.

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•

We recorded costs of $64.1 million after-tax, or $.40 per share, associated with our corporate-wide workforce reduction program.

•

Our merchant energy business recorded impairments that total $30.5 million after-tax, or $.19 per share, primarily due to the termination of certain planned development projects and due to a decline in value of an investment in a power project.

•

Our other nonregulated businesses recorded $69.7 million after-tax, or $.43 per share, impairments of certain real estate projects, senior-living facilities, and international assets. This was a result of our decision to sell certain non-core assets and accelerate the exit strategies on other assets that we will continue to hold and own over the next several years, as well as an other than temporary decline in the value of our equity method Bolivian investment.

•

Our financial investments business recorded a $2.8 million after-tax, or $.02 per share, reduction of its investment in an aircraft due to the decline in value of used airplanes as a result of the September 11, 2001 terrorist attacks and the general downturn in the aviation industry.

        These decreases were partially offset by the following:

•

Our merchant energy business recorded in 2000 an expense of $15.0 million after-tax, or $.10 per share, for a deregulation transition cost to Goldman Sachs.

•

BGE recorded an expense of $4.2 million after-tax, or $.03 per share, for its employees that elected to participate in a targeted VSERP in 2000 that had a negative impact in that year.

•

We recorded an $8.5 million after-tax, or $.05 per share, gain for the cumulative effect of adopting Statement of Financial Accounting Standard (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, in the first quarter of 2001.

•

Net income before special costs increased $.17 per share compared to 2000 as discussed in more detail below.

        Net income before special costs was $417.2 million, or $2.60 per share, in 2001 compared to $364.5 million, or $2.43 per share, in 2000. Net income before special costs were higher compared to 2000 mostly because BGE recorded $75.0 million pre-tax, or approximately $.30 per share, of amortization expense for the reduction of our generating plants associated with the Restructuring Order in 2000 that had a negative impact in that year. In addition, we had higher earnings from our regulated gas business in 2001 mostly because of increases in the sharing mechanism under our gas cost adjustment clauses and the increase in our base rates. These increases were offset by the impact of a 6.5% annual electric residential rate reduction that was effective July 1, 2000, and decreases in earnings from our other nonregulated businesses.

        Net income before special costs from our other nonregulated businesses decreased primarily due to declining equity values and lower gains on sales of equity securities in our financial investments business.

2000

Our 2000 total net income increased $85.2 million, or $.56 per share, compared to 1999 mostly because we recorded an extraordinary charge of $66.3 million after-tax, or $.44 per share, associated with the deregulation of the electric generation portion of our business in 1999. In addition, we recorded several special costs in 1999 that had a negative impact in that year as follows:

•

Our regulated electric business recorded $4.9 million after-tax, or $.03 per share, of expenses related to Hurricane Floyd.

•

Our generation operation recorded impairments of certain power projects of $14.2 million after-tax, or $.09 per share.

•

Our Latin American operation recorded a $4.5 million after-tax, or $.03 per share, impairment of an investment in a power project.

•

Our financial investments business recorded a $16.0 million after-tax, or $.11 per share, reduction of a financial investment.

•

Our real estate and senior-living facilities business recorded a $5.8 million after-tax, or $.04 per share, impairment of certain senior-living facilities.

        These were partially offset by the following special costs in operations recorded in 2000:

•

$15.0 million after-tax deregulation transition cost in June 2000 to Goldman Sachs incurred by our power marketing operation to provide BGE's standard offer service requirements, and

•

$4.2 million after-tax expense during the first and second quarters of 2000 for BGE employees that elected to participate in a targeted VSERP.

        Net income before special costs was $364.5 million, or $2.43 per share, in 2000 compared to $371.8 million, or $2.48 per share, in 1999. Net income before special costs included in operations decreased mostly because we recognized $29.9 million, or $18.1 million after-tax, of the 6.5% annual residential rate reduction that was effective July 1, 2000, and we had higher interest costs in 2000 compared to 1999. We also recognized $5.7 million after-tax, or $.04 per share, for contributions to the universal service fund relating to the implementation of the deregulation of electric generation, starting July 1, 2000. These decreases were offset partially by higher earnings in our merchant energy and our other nonregulated businesses.

        In 2000, net income from our merchant energy business before special costs increased compared to 1999 because of higher earnings in both our power marketing and generation operations.

        In 2000, net income from our other nonregulated businesses increased mostly because of higher earnings in our financial investments operation.

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

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Merchant Energy Business

Our merchant energy business is exposed to various market risks as discussed further in Item 7. Management's Discussion and Analysis—Market Risk section.

        We record the financial impacts of these market risks in earnings in different periods depending upon which portion of our merchant energy business they affect.

•

We record changes in the value of contracts in our power marketing operation that are subject to mark-to-market accounting in earnings in the period in which the change occurs.

•

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

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

        As discussed in the Business Environment—Electric Competition section, our merchant energy business was significantly impacted by the July 1, 2000 implementation of customer choice in Maryland. At that time, BGE's generating assets became part of our nonregulated merchant energy business, and Constellation Power Source began selling to BGE the energy and capacity required to meet its standard offer service obligations for the first three years (July 1, 2000 to June 30, 2003) of the transition period. In August 2001, BGE entered into a contract with Constellation Power Source to provide 90% of the energy and capacity required for BGE to meet its standard offer service requirements for the final three years (July 1, 2003 to June 30, 2006) of the transition period.

        In addition, effective July 1, 2000, the merchant energy business revenues include 90% of the competitive transition charges (CTC revenues) BGE collects from its customers and the portion of BGE's revenues providing for nuclear decommissioning costs.

Net Income

		2001			2000			1999
		(In millions)
Revenues		$	1,765.5		$	1,025.7		$	277.3
Operating expenses			1,082.3			586.8			151.5
Workforce reduction costs			46.0			—			—
Contract termination related costs			224.8			—			—
Impairment losses and other costs			46.9			—			21.4
Depreciation and amortization			174.9			83.6			7.5
Taxes other than income taxes			49.4			24.6			—
Income from Operations		$	141.2		$	330.7		$	96.9
Net Income		$	93.1		$	198.6		$	52.4
Net Income Before Special Costs Included in Operations		$	291.2		$	213.6		$	66.6
	Workforce reduction costs		(28.0	)		—			—
	Contract termination related costs		(139.6	)		—			—
	Deregulation transition cost		—			(15.0	)		—
	Impairment of power projects		(30.5	)		—			(14.2	)
Net Income		$	93.1		$	198.6		$	52.4

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 3 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

Revenues

Merchant energy revenues increased $739.8 million during 2001 compared to 2000 mostly due to:

•

supplying BGE's standard offer service requirements for a full year in 2001 as compared to six months in 2000,

•

higher revenues from other sales of generation, including new peaking facilities and Nine Mile Point, and

•

higher mark-to-market energy revenues.

        Merchant energy revenues increased $748.4 million during 2000 compared to 1999 mostly due to:

•

providing BGE's standard offer service requirements effective July 1, 2000, and

•

higher revenues from our generation and power marketing operations.

        We discuss the revenues from our generation and power marketing operations below.

Revenues from BGE Standard Offer Service

Our merchant energy business provided BGE's standard offer service requirements for a full year in 2001 as compared to six months in 2000. As a result, merchant energy revenues increased $578.0 million in 2001, including CTC and decommissioning revenues that increased $74.4 million.

        Merchant energy revenues increased $691.0 million, including $110.0 million of CTC and decommissioning

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revenues, in 2000 compared to 1999 related to providing BGE's standard offer service requirements effective July 1, 2000.

Other Generation Revenues

Other generation revenues increased $142.2 million in 2001 as compared to 2000 primarily due to the construction of new power plants and the acquisition of Nine Mile Point, as well as additional sales from our existing facilities. Revenues from peaking facilities that commenced operations during midsummer 2001 totaled $83.6 million, and revenues from Nine Mile Point, which we acquired in November 2001, totaled $55.2 million.

        Additionally, sales of power from our Baltimore plants in excess of that required to serve BGE's standard offer service requirements increased $51.2 million. Our generation operation also recognized a $9.5 million gain on the sale of a project under development in the PJM region in March 2001.

        These increases were partially offset by the following:

•

Revenues associated with the California power purchase agreements decreased $22.0 million. We discuss the California power purchase agreements.

•

In April 2000, our generation operation terminated an operating arrangement and sold certain subsidiaries of Constellation Operating Services Inc. (COSI) to Orion. COSI ended its exclusive arrangement with Orion to operate Orion's facilities, and Orion purchased from COSI the four subsidiary companies formed to operate power plants owned by Orion. Our generation operation recognized a $13.3 million gain on this sale in 2000 which had a positive impact on that year, and we also had lower revenues during 2001 compared to 2000 due to the sale of these subsidiaries.

        Other generation revenues increased $47.6 million during 2000 compared to 1999 mostly because of the following:

•

sales of power from our Baltimore plants in excess of that required to serve BGE's standard offer requirements totaled $40.7 million, and

•

our generation operation recognized a $13.3 million gain on the termination of an operating arrangement and the sale of certain subsidiaries of COSI as discussed above.

        These increases were partially offset by a decrease of $14.9 million in revenues associated with our California power purchase agreements. We discuss the California power purchase agreements below.

        The significant decline in the long-term prices of electricity since early 2001 has affected, and may continue to affect, our facilities that have not entered into contracts for the sale of their generation.

        Under the Restructuring Order, larger industrial customers have available standard offer service until June 30, 2002. Beginning in July 2002, approximately 1,000 megawatts of industrial customer load will move from BGE's standard offer service to market-based rates. As a result, our merchant energy business will have an increasing amount of generating capacity that will be sold at wholesale market rates and thus be subject to future changes in wholesale electricity prices. Refer to the Business Environment section for further discussion.

California Power Purchase Agreements

Our generation operation has $296.4 million invested in 14 operating projects of which our ownership percentage represents 146 megawatts of electricity that are sold in California to PGE and SCE under power purchase agreements called SO4 agreements.

        Under these agreements, the projects supply electricity to these utilities at variable rates. Revenues from these projects were $22.1 million in 2001 compared to $44.1 million in 2000. Revenues decreased because of lower power prices in California during the second half of 2001. While energy rates were higher during the first half of 2001, the higher rates were offset by reserves established for our exposure in California during that period.

        As previously discussed in the Business Environment—Other States section, the projects entered into agreements with PGE and SCE that provide for five-year fixed-price payments averaging $53.70 per megawatt-hour plus the stated capacity payments in the original SO4 contracts. We expect the revenues from these projects to be lower in 2002 compared to 2001.

        We also describe these projects in Note 11.

Mark-to-Market Energy Revenues

Mark-to-market energy revenues include net gains and losses from Constellation Power Source origination and risk management activities for which the mark-to-market method of accounting is required by Emerging Issues Task Force Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. We discuss the mark-to-market method of accounting and Constellation Power Source's activities in more detail in the Critical Accounting Policies section and in Note 1.

        As a result of the nature of its operations and the use of mark-to-market accounting for certain activities, Constellation Power Source's revenues and earnings will fluctuate. We cannot predict these fluctuations, but the impact on our revenues and earnings could be material. We discuss our market risk in more detail in Item 7. Management's Discussion and Analysis—Market Risk section. The primary factors that cause fluctuations in our revenues and earnings are:

•

the number, size, and profitability of new transactions,

•

the magnitude and volatility of changes in commodity prices and interest rates, and

•

the number and size of our open commodity and derivative positions.

        Mark-to-market energy revenues were as follows:

		2001			2000			1999
		(In millions)
New origination transactions		$	227.0		$	158.8		$	141.5
Risk management activities
	Realized		19.7			(57.0	)		22.2
	Unrealized		(70.9	)		49.7			(16.0	)
Total risk management activities			(51.2	)		(7.3	)		6.2
Total		$	175.8		$	151.5		$	147.7

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        Revenues from new origination transactions represent the initial unrealized fair value of new wholesale energy transactions at the time of contract execution. Risk management revenues represent both realized and unrealized gains and losses from changes in the value of our entire portfolio. We discuss the changes in origination and risk management revenues below.

        Constellation Power Source's mark-to-market revenues are influenced by our focus on serving the full electric energy and capacity requirements of electric utility customers. Providing utilities' full energy and capacity requirements requires greater ownership of or contractual access to power generating facilities, as opposed to merely standard products obtainable in liquid trading markets.

        In order to enable us to serve such customers, during 2000 and 2001, we obtained access to physical power by entering into a portfolio of tolling arrangements and other physical delivery energy contracts. Tolling arrangements are contracts which provide us the right, but not the obligation, to purchase power at a price linked to the variable cost of production, including fuel. This inventory of energy supply somewhat exceeded the energy demands from existing transactions and provides resources to enable us to close additional transactions.

        The relationship of the realized portion of revenue to total mark-to-market energy revenue in the table on the previous page reflects the nature of the origination transactions which Constellation Power Source has executed. A significant portion of these contracts provided for Constellation Power Source to serve customers' energy requirements at fixed prices that were lower in the early years of the contracts but that are expected to provide increased margins and cash flows over the remaining terms of the contracts. We discuss the settlement terms of our contracts on the next page.

        Mark-to-market energy revenues increased $24.3 million during 2001 compared to 2000 mostly because of higher revenues from new origination transactions, partially offset by net losses from risk management activities. The increase in origination revenue reflects primarily new full-requirements load-serving transaction volumes, primarily in New England and Texas which were enabled by the portfolio of physical supply arrangements discussed above. The increase in net losses from risk management activities is primarily due to decreases in both future power prices and price volatility during 2001 and costs of establishing hedges for new origination transactions. The decrease in forward price and volatility negatively affected the mark-to-market value of our portfolio of supply arrangements. These mark-to-market losses were, however, more than offset by mark-to-market gains in the form of new origination transactions that were in part enabled by these supply arrangements.

        Mark-to-market energy revenues increased $3.8 million during 2000 compared to 1999 due to increased origination revenue, which was offset partially by net losses from risk management activities. The increase in origination revenue reflects new transaction volumes, primarily in New England, the Mid-Atlantic, and Texas. The net losses from risk management activities resulted from realized losses in serving the initial year of long-term, fixed-price energy sales contracts as described above, substantially offset by unrealized gains on portions of the portfolio which benefited from the increases in future power prices and price volatility during 2000.

        Constellation Power Source's mark-to-market energy assets and liabilities are comprised of a combination of derivative and non-derivative contracts. While some of these contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both.

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

At December 31,	2001		2000
	(In millions)
Current Assets	$	398.4	$	453.1
Noncurrent Assets		1,819.8		2,069.3
Total Assets		2,218.2		2,522.4
Current Liabilities		323.3		358.2
Noncurrent Liabilities		1,476.5		1,636.3
Total Liabilities		1,799.8		1,994.5
Net mark-to-market energy asset	$	418.4	$	527.9

        Following are the primary sources of the change in net mark-to-market energy asset during 2001:

Change in Net Mark-to-Market Energy Asset
(In millions)
Fair value at December 31, 2000						$	527.9
Changes in fair value recorded as revenues
	New origination transactions		$	227.0
	Unrealized risk management revenues:
		Contracts settled		(19.7	)
		Changes in valuation techniques		4.5
		Unrealized changes in fair value		(55.7	)
Total unrealized risk management revenues			$	(70.9	)
Total changes in fair value recorded as revenues							156.1
Changes in fair value recorded as operating expenses							(15.0	)
Net change in premiums on options							(242.2	)
Other changes in fair value							(8.4	)
Fair value at December 31, 2001						$	418.4

        New origination transactions represent the initial unrealized fair value at the time these contracts are executed. Changes in valuation techniques represent improvements in the models used to value our portfolio to reflect more accurately the economic value of our contracts. Unrealized changes in fair value represents the change in value of our unrealized mark-to-market energy net

35

asset due to changes in commodity prices, the volatility of options on commodities, the time value of options, and net changes in valuation allowances. Changes in fair value recorded as operating expenses represent accruals for future incremental expenses in connection with servicing origination transactions. While these accruals are reductions in the fair value of the net mark-to-market energy asset, they are recorded in the income statement as expenses rather than revenue. The net change in premiums on options reflects a net increase in options sold during 2001. We record premiums on options purchased as an increase in the net mark-to-market energy asset and premiums on options sold as a decrease in the net mark-to-market energy asset. Prior to 2001, we had entered into purchased option and energy tolling contracts in connection with serving our energy sales contracts. The option and tolling contracts, by their nature, exposed us to changes in the volatility of energy prices. During 2001, we sold options to reduce our exposure to option volatility.

        The settlement term of the net mark-to-market energy asset and sources of fair value as of December 31, 2001 are as follows:

	Settlement Term
																				Total Fair Value
	2002		2003		2004			2005		2006		2007			2008-2009		Thereafter
	(In millions)
Prices provided by external sources	$	67.0	$	10.8	$	25.8		$	41.8	$	26.8	$	(0.7	)	$	4.0	$	0.4		$	175.9
Prices based on models		8.2		25.9		(2.4	)		47.9		48.1		50.2			84.4		(19.8	)		242.5
Total net mark-to-market energy asset	$	75.2	$	36.7	$	23.4		$	89.7	$	74.9	$	49.5		$	88.4	$	(19.4	)	$	418.4

        Constellation Power Source manages its risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, we record and manage the energy purchase and sale obligations under our contracts in separate components based upon the commodity (e.g., electricity or gas), the product (e.g., electricity for delivery during peak or off-peak hours), the delivery location (e.g., by region), the risk profile (e.g., forward or option), and the delivery period (e.g., by month and year). Consistent with our risk management practices, we have presented the information in the table above based upon the ability to obtain reliable prices for components of the risks in our contracts from external sources rather than on a contract-by-contract basis. Thus, the portion of long-term contracts that is valued using external price sources is classified in the same caption as other shorter-term transactions that settle in the same period. This presentation is consistent with how we manage our risk, and we believe it provides the best indication of the basis for the valuation of our portfolio. Since we manage our risk on a portfolio basis rather than contract-by-contract, it is not practicable to determine separately the portion of long-term contracts that is included in each valuation category. We describe the commodities, products, and delivery periods included in each valuation category in detail below.

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

•

forward purchases and sales of electricity during peak hours for delivery terms of four to six years, depending upon the region,

•

forward purchases and sales of electricity during off-peak hours for delivery terms of two to four years, depending upon the region,

•

options for the purchase and sale of electricity for delivery terms of up to two years,

•

forward purchases and sales of electric capacity for delivery terms of up to two years,

•

forward purchases and sales of natural gas and oil for delivery terms of up to four years, and

•

options for the purchase and sale of natural gas and oil for delivery terms of up to two years.

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

        Modeling techniques include estimating the present value of cash flows based upon underlying contractual terms and incorporate, where appropriate, option pricing models and statistical simulation procedures. Inputs to the models include observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlation of energy commodity prices, contractural volumes, and estimated volumes for requirements contracts. Additionally, we incorporate counterparty-specific credit quality and factors for market price uncertainty and other risks in our valuation. The inputs and factors used to determine fair value reflect management's best estimates.

        The electricity, fuel, and other energy contracts held by Constellation Power Source 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

36

commodities has not developed, the majority of contracts used in the power marketing business are direct contracts between market participants and are not exchange-traded or financially settling contracts that readily can be liquidated in their entirety through an exchange or other market mechanism. Consequently, Constellation Power Source and other market participants generally realize the value of these contracts as cash flows become due or payable under the terms of the contracts rather than through selling or liquidating the contracts themselves.

        Consistent with our risk management practices, the amounts shown in the table on the previous page as being valued using prices from external sources include the portion of long-term contracts for which we can obtain reliable prices from external sources. The remaining portions of these long-term contracts are shown in the table as being valued using models. In order to realize the entire value of a long-term contract in a single transaction, we would need to sell or assign the entire contract. If we were to sell or assign any of our long-term contracts in their entirety, we may not realize the entire value reflected in the table. However, based upon the nature of the power marketing business, we expect to realize the value of these contracts, as well as any contracts we may enter into in the future to manage our risk, over time as the contracts and related hedges settle in accordance with their terms. We do not expect to realize the value of these contracts and related hedges by selling or assigning the contracts themselves in total.

        The fair values in the table represent expected future cash flows based on the level of forward prices and volatility factors as of December 31, 2001. These amounts do not represent the contractual maturities and could change significantly as a result of future changes in these factors. Additionally, because the depth and liquidity of the power markets varies substantially between regions and time periods, the prices used to determine fair value could be affected significantly by the volume of transactions executed. Constellation Power Source's management uses its best estimates to determine the fair value of commodity and derivative contracts it holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors, and credit exposure. However, it is possible that future market prices could vary from those used in recording mark-to-market energy assets and liabilities, and such variations could be material.

Operating Expenses

Merchant energy operating expenses increased $495.5 million during 2001 compared to 2000 mostly because of the following:

•

Fuel and purchased energy costs increased $291.5 million and operations and maintenance costs increased $236.7 million. These increases reflect a full year's operation of the generation plants that were transferred from BGE effective July 1, 2000, as well as, the added operations of the new peaking facilities and Nine Mile Point. The fuel cost increase also reflects higher fuel prices for generating electricity. Coal prices increased during 2001, and we expect to incur additional costs in the future to operate our coal generating facilities due to higher prices.

•

Power marketing operating expenses associated with the growth of the operation increased $31.6 million.

        These increased costs were partially offset by lower fees earned by Goldman Sachs at our power marketing operation due to the termination of the power business services agreement in October 2001. The Goldman Sachs fees were $28.9 million in 2001, $81.3 million in 2000, and $31.8 million in 1999. The amount of fees for 2000 includes the $24.0 million, or $.10 per share, deregulation transition cost as discussed below. These fees will not be incurred in the future due to the termination of the power business services agreement with Goldman Sachs. In addition, COSI had lower operating expenses due to the sale of certain subsidiaries to Orion, as previously discussed.

        Operating expenses increased $435.3 million in 2000 compared to 1999 mostly because of three factors:

•

an increase of $191.6 million in fuel costs and $157.2 million in operations and maintenance costs associated with the generation plants that were transferred from BGE effective July 1, 2000,

•

an increase in Goldman Sachs fees of $49.5 million, including the $24.0 million deregulation transition cost incurred by our power marketing operation to provide BGE's standard offer service requirements, and

•

a $6.2 million increase in power marketing operating expenses associated with the growth of the operation.

        In light of the events of September 11, 2001, we have taken additional security measures at our nuclear facilities. While we anticipate continuing to incur additional security related costs at our nuclear facilities, we do not expect that these costs will be material. However, the Nuclear Regulatory Commission (NRC) currently is evaluating additional security measures that may be required at nuclear facilities. At this time, we cannot determine the impact on our financial results of any additional security measures that may be required by the NRC.

Extended Nuclear Outages

Our merchant energy business will experience extended outages at Calvert Cliffs to replace the steam generators during the 2002 refueling outage for Unit 1 and during the 2003 refueling outage for Unit 2. As a result of the extended outages, we expect lower annual revenues and higher annual operating costs for each extended outage.

Workforce Reduction Costs, Contract Termination Related Costs, and Impairment Losses and Other Costs

As previously discussed in the Events of 2001 section, our merchant energy business recognized the following:

•

$46.0 million, or $.17 per share, of expenses associated with our workforce reduction efforts,

•

$224.8 million, or $.87 per share, of expenses related to the termination of the power business services agreement with Goldman Sachs,

37

•

a $40.8 million, or $.16 per share, impairment of certain planned development projects that were terminated, and

•

a $6.1 million, or $.03 per share, loss on the impairment of a power project.

        As a result of our workforce reduction efforts, our merchant energy business expects to generate annual savings of approximately $24 million.

        In 1999, our generation operation recorded a $21.4 million, or $.09 per share, write-off of two geothermal power projects, which had a negative impact in that year.

        We discuss these workforce reduction costs, contract termination related costs, and impairment losses and other costs further in Note 2.

Depreciation and Amortization Expense

Merchant energy depreciation and amortization expense increased $91.3 million in 2001 compared to 2000 mostly because 2001 includes a full year of expenses associated with the generation plants that were transferred from BGE effective July 1, 2000. Additionally, 2001 expenses include depreciation and amortization associated with the new peaking facilities and Nine Mile Point.

        Merchant energy depreciation and amortization expense increased $76.1 million in 2000 compared to 1999 mostly because of $73.8 million of expenses associated with the generation plants that were transferred from BGE effective July 1, 2000.

Taxes Other than Income Taxes

Merchant energy taxes other than income taxes increased in 2001 and 2000 compared to their respective prior year mostly because of taxes other than income taxes associated with the generation plants that were transferred from BGE effective July 1, 2000.

Regulated Electric Business

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

Net Income

		2001			2000			1999
		(In millions)
Electric revenues		$	2,040.0		$	2,135.2		$	2,260.0
Electric fuel and purchased energy			1,192.8			870.7			487.7
Operations and maintenance			258.7			447.2			629.6
Workforce reduction costs			55.7			7.0			—
Depreciation and amortization			173.3			319.9			376.4
Taxes other than income taxes			139.5			157.8			188.9
Income from Operations		$	220.0		$	332.6		$	577.4
Net Income Before Extraordinary Item		$	50.9		$	102.3		$	265.1
Extraordinary loss			—			—			(66.3	)
Net Income		$	50.9		$	102.3		$	198.8
Net Income Before Special Costs Included in Operations and Extraordinary Item		$	84.5		$	106.5		$	270.0
	Workforce reduction costs		(33.6	)		(4.2	)		—
	Hurricane Floyd		—			—			(4.9	)
Extraordinary loss			—			—			(66.3	)
Net Income		$	50.9		$	102.3		$	198.8

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 3 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

Electric Revenues

The changes in electric revenues in 2001 and 2000 compared to the respective prior year were caused by:

	2001			2000
	(In millions)
Electric system sales volumes	$	2.8		$	40.9
Rates		(79.3	)		(119.9	)
Fuel rate surcharge		30.5			12.6
Total change in electric revenues from electric system sales		(46.0	)		(66.4	)
Interchange and other sales		(53.8	)		(58.3	)
Other		4.6			(0.1	)
Total change in electric revenues	$	(95.2	)	$	(124.8	)

Electric System Sales Volumes

"Electric system sales volumes" are sales to customers in BGE's service territory at rates set by the Maryland PSC. As part of the Restructuring Order, the rates received from customers under the standard offer service increase over the transition period as discussed further in the Business Environment—Electric Competition section. These sales do not include interchange sales and sales to others.

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        The percentage changes in our electric system sales volumes, by type of customer, in 2001 and 2000 compared to the respective prior year were:

	2001		2000
Residential	0.3	%	2.9	%
Commercial	0.7		3.5
Industrial	(0.7	)	2.9

        In 2001, we sold about the same amount of electricity to all customer classes compared to 2000 due primarily to milder winter weather offset by an increased number of customers.

        In 2000, we sold more electricity to residential customers compared to 1999 due to colder winter weather, higher usage per customer, and an increased number of customers, offset partially by mild summer weather. We sold more electricity to commercial customers mostly due to higher usage per customer and an increased number of customers. We sold more electricity to industrial customers due to higher usage by Bethlehem Steel and an increased number of customers, offset partially by lower usage by other industrial customers. Usage was higher at Bethlehem Steel in 2000 as a result of a 1999 shut down for a planned upgrade to their facilities that temporarily reduced their electricity consumption in that year.

Rates

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

        Rate revenues decreased in 2001 compared to 2000 mostly due to:

•

the 6.5% annual residential rate reduction of $17.6 million recorded through June 30, 2001, and

•

$74.4 million of revenues that were transferred to the merchant energy business discussed above.

        These decreases were partially offset by the increase in the standard offer service rate that BGE charges its customers and other net impacts of the rate restructuring discussed above.

        Rate revenues decreased in 2000 compared to 1999 mostly because of the $29.9 million decrease caused by the 6.5% annual residential rate reduction, and the $110.0 million transfer of revenues to the merchant energy business. This was offset partially by higher fuel rate revenues during the first half of 2000.

Fuel Rate Surcharge

In September 2000, the Maryland PSC approved the collection of the $54.6 million accumulated difference between our actual costs of fuel and energy and the amounts collected from customers that were deferred under the electric fuel rate clause through June 30, 2000. We discuss this further in the Electric Fuel Rate Clause section below.

Interchange and Other Sales

"Interchange and other sales" are sales in the PJM energy market and to others. PJM is a RTO/ISO that also operates a regional power pool with members that include many wholesale market participants, as well as BGE and other utility companies. Prior to the implementation of customer choice, BGE sold energy to PJM members and to others after it had satisfied the demand for electricity in its own system.

        Effective July 1, 2000, BGE no longer engages in interchange sales, and these activities are included in our merchant energy business, which resulted in a decrease in interchange and other sales for 2001 and 2000 compared to their respective prior year. In addition, BGE had lower interchange and other sales during the first half of 2000 when increased demand for system sales reduced the amount of energy BGE had available for off-system sales.

Electric Fuel and Purchased Energy Expenses

	2001		2000		1999
	(In millions)
Actual costs	$	1,150.5	$	868.0	$	558.0
Net recovery (deferral) of costs under electric fuel rate clause		42.3		2.7		(70.3	)
Total electric fuel and purchased energy expenses	$	1,192.8	$	870.7	$	487.7

Actual Costs

As discussed in the Business Environment—Electric Competition section, effective July 1, 2000, BGE transferred its generating assets to, and began purchasing substantially all of the energy and capacity required to provide electricity to standard offer service customers from, the merchant energy business.

        Our actual costs of fuel and purchased energy increased in 2001 compared to 2000 mostly because of the deregulation of electric generation. The higher amount BGE paid for purchased energy from our merchant energy business is offset by the absence of $206.4 million in 2001 and $191.6 million in 2000 in fuel costs, and lower operations and maintenance, depreciation, taxes, and other costs at BGE as a result of no longer owning and operating the transferred electric generation plants.

        Prior to July 1, 2000, BGE's purchased fuel and energy costs only included actual costs of fuel to generate electricity (nuclear fuel, coal, gas, or oil) and electricity we bought from others.

Electric Fuel Rate Clause

Prior to July 1, 2000, we deferred (included as an asset or liability on the Consolidated Balance Sheets and excluded from the Consolidated Statements of Income) the difference between our actual costs of fuel and energy and what we collected from

39

customers under the fuel rate in a given period. Effective July 1, 2000, the fuel rate clause was discontinued under the terms of the Restructuring Order. In September 2000, the Maryland PSC approved the collection of the $54.6 million accumulated difference between our actual costs of fuel and energy and the amounts collected from customers that were deferred under the electric fuel rate clause through June 30, 2000. We collected this accumulated difference from customers over the twelve-month period ended October 2001.

Electric Operations and Maintenance Expenses

Regulated electric operations and maintenance expenses decreased $188.5 million during 2001 compared to 2000 mostly because effective July 1, 2000, costs of $194.7 million were no longer incurred by this business segment. These costs were associated with the electric generation assets that were transferred to the merchant energy business.

        Regulated electric operations and maintenance expenses decreased $182.4 million during 2000 compared to 1999 mostly because effective July 1, 2000, $157.2 million of costs were no longer incurred by this business segment. These costs were associated with the electric generation assets that were transferred to the merchant energy business. In addition, 1999 operations and maintenance expenses included costs for system restoration activities related to Hurricane Floyd and a major winter ice storm, and costs associated with the preparation for the year 2000 (Y2K). These costs had a negative impact in that year.

Workforce Reduction Costs

In 2001, BGE's electric business recognized $55.7 million, or $.21 per share, of expenses associated with our workforce reduction efforts. As a result of our workforce reduction efforts, our regulated electric business expects to generate annual savings of approximately $36 million. In 2000, BGE's electric business recognized $7.0 million, or $.03 per share, of expenses for employees that elected to participate in a targeted VSERP that had a negative impact in that year. We discuss these programs further in Note 2.

Electric Depreciation and Amortization Expense

Regulated electric depreciation and amortization expense decreased $146.6 million during 2001 compared to 2000 mostly due to:

•

the absence of $75.0 million of amortization expense recorded in 2000 associated with the $150 million reduction of our generating plants provided for in the Restructuring Order, and

•

$75.1 million of expenses associated with the transfer of the generation assets to the merchant energy business effective July 1, 2000.

        Regulated electric depreciation and amortization expense decreased $56.5 million during 2000 compared to 1999 mostly because of the absence of $73.8 million of depreciation and amortization expense associated with the transfer of the generation assets. This decrease was offset partially by more electric plant in service and higher amortization associated with regulatory assets.

Electric Taxes Other Than Income Taxes

Regulated electric taxes other than income taxes decreased $18.3 million during 2001 compared to 2000 mostly due to the absence of taxes other than income taxes associated with the generation assets that were transferred to the merchant energy business effective July 1, 2000 partially offset by fewer tax credits.

        Regulated electric taxes other than income taxes decreased $31.1 million during 2000 compared to 1999. This was mostly due to two factors:

•

regulated electric taxes other than income taxes reflect the absence of $23.8 million of taxes other than income taxes associated with the generation assets that were transferred to the merchant energy business effective July 1, 2000, and

•

comprehensive changes to the tax laws.

        The comprehensive tax law changes are discussed further in Note 5.

Regulated Gas Business

Net Income

		2001			2000		1999
		(In millions)
Gas revenues		$	680.7		$	611.6	$	488.1
Gas purchased for resale			401.3			350.6		233.8
Operations and maintenance			104.3			100.6		97.7
Workforce reduction costs			1.3			—		—
Depreciation and amortization			47.7			46.2		44.9
Taxes other than income taxes			34.3			34.8		34.5
Income from Operations		$	91.8		$	79.4	$	77.2
Net Income		$	37.5		$	30.6	$	33.0
Net Income Before Special Costs Included in Operations		$	38.3		$	30.6	$	33.0
	Workforce reduction costs		(0.8	)		—		—
Net Income		$	37.5		$	30.6	$	33.0

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 3 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

        Net income from our regulated gas business increased during 2001 compared to 2000 mostly due to the sharing mechanism under our gas cost adjustment clauses and the increase in our base rates.

        Net income from the regulated gas business decreased during 2000 compared to 1999 mostly due to a slight increase in operations and maintenance and depreciation expenses partially offset by an increase in our base rates.

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

40

Gas Revenues

The changes in gas revenues in 2001 and 2000 compared to the respective prior year were caused by:

	2001			2000
	(In millions)
Gas system sales volumes	$	(3.4	)	$	34.5
Base rates		3.3			2.7
Weather normalization		11.9			(26.7	)
Gas cost adjustments		43.6			54.7
Total change in gas revenues from gas system sales		55.4			65.2
Off-system sales		12.5			58.1
Other		1.2			0.2
Total change in gas revenues	$	69.1		$	123.5

Gas System Sales Volumes

The percentage changes in our gas system sales volumes, by type of customer, in 2001 and 2000 compared to the respective prior year were:

	2001		2000
Residential	(7.8	)%	13.0	%
Commercial	3.5		12.8
Industrial	(25.2	)	(2.1	)

        We sold less gas to residential customers during 2001 compared to 2000 mostly due to milder winter weather and lower usage per customer partially offset by an increased number of customers. We sold more gas to commercial customers mostly due to higher usage per customer. We sold less gas to industrial customers mostly because of lower usage by Bethlehem Steel and other industrial customers due to their switching to lower cost alternative fuel sources and lower business needs related to the general downturn in the economy partially offset by an increased number of customers.

        We sold more gas to residential and commercial customers during 2000 compared to 1999 due to higher usage per customer, colder weather, and an increased number of customers. We sold less gas to industrial customers mostly because of lower usage by Bethlehem Steel and other industrial customers partially offset by an increased number of customers.

Base Rates

Base rate revenues increased during 2001 and 2000 compared to the respective prior year mostly because the Maryland PSC authorized a $6.4 million annual increase in our base rates effective June 22, 2000.

Weather Normalization

The Maryland PSC allows us to record a monthly adjustment to our gas revenues to eliminate the effect of abnormal weather patterns on our gas system sales volumes. This means our monthly gas revenues are based on weather that is considered "normal" for the month and, therefore, are not affected by actual weather conditions.

Gas Cost Adjustments

We charge our gas customers for the natural gas they purchase from us using gas cost adjustment clauses set by the Maryland PSC as described in Note 1. However, under market-based rates, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers. The shareholders' portion increased $3.6 million during 2001 compared to 2000. Effective November 2001, the Maryland PSC approved an order that modifies certain provisions of the market-based rates incentive mechanism. These provisions require that BGE secure fixed-price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for the November through March period. These fixed price contracts are not subject to sharing under the market-based rates incentive mechanism. We do not expect these changes to have a material impact on our financial results.

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

        Gas cost adjustment revenues increased during 2001 compared to 2000 mostly because the gas we sold to non-delivery service customers was at a higher price partially offset by less gas sold. In the first half of 2001, the revenue increase reflects the significant increase in natural gas prices.

        Gas cost adjustment revenues increased during 2000 compared to 1999 mostly because we sold more gas at a higher price. The revenue increase reflects the significant increase in natural gas prices.

Off-System Sales

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

        Revenues from off-system gas sales increased during 2001 compared to 2000 mostly because the gas we sold off-system was at a higher price partially offset by less gas sold. In the first half of 2001, the revenue increase reflects the significant increase in natural gas prices.

        Revenues from off-system gas sales increased during 2000 compared to 1999 mostly because we sold more gas off-system at significantly higher prices.

Gas Purchased For Resale Expenses

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

41

        Our gas costs increased during 2001 compared to 2000 mostly because gas we purchased was at a higher price partially offset by less gas purchased for both system and off-system sales. Our gas costs increased during 2000 compared to 1999 mostly because we bought more gas for both system and off-system sales, and all of the gas purchased was at a higher price due to the significant increase in natural gas prices during 2000.

Other Gas Operating Expenses

Other gas operating expenses were about the same during 2001 and 2000 compared to the respective prior year.

        As a result of our workforce reduction efforts, our regulated gas business expects to generate annual savings of approximately $12 million. The cost of these programs was deferred as a regulatory asset. See Note 6.

Other Nonregulated Businesses

Net Income

			2001			2000		1999
			(In millions)
Revenues			$	602.1		$	713.3	$	848.4
Operating expenses				510.7			588.8		771.5
Workforce reduction costs				2.7			—		—
Impairment losses and other costs				155.2			—		42.9
Depreciation and amortization				23.2			20.3		21.0
Taxes other than income taxes				3.4			4.3		3.9
(Loss) Income from Operations			$	(93.1	)	$	99.9	$	9.1
Net (Loss) Income Before Cumulative Effect of Change in Accounting Principle			$	(99.1	)	$	13.8	$	(24.1	)
Cumulative Effect of Change in Accounting Principle				8.5			—		—
Net (Loss) Income			$	(90.6	)	$	13.8	$	(24.1	)
Net Income Before Special Costs
	Included in Operations		$	3.2			$13.8	$	2.2
		Workforce reduction costs		(1.7	)		—		—
		Loss on sale of Guatemalan operations		(28.1	)		—		—
		Impairment of real estate, senior-living, and international investments		(69.7	)		—		(10.3	)
		Reduction of financial investment		(2.8	)		—		(16.0	)
Net (Loss) Income Before Cumulative Effect of Change in Accounting Principle				(99.1	)		13.8		(24.1	)
Cumulative Effect of Change in Accounting Principle				8.5			—		—
Net (Loss) Income			$	(90.6	)		$13.8	$	(24.1	)

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 3 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

        Net income from our other nonregulated businesses decreased during 2001 compared to 2000 mostly because of the following items:

•

Our Latin American operations recorded a loss of $28.1 million after-tax, or $.17 per share, on the sale of our Guatemalan operations.

•

We recorded $69.7 million after-tax, or $.43 per share, in impairments of certain non-core assets. We decided to sell six real estate projects without further development and all of our senior-living facilities in 2002 and accelerate the exit strategies for two other real estate projects that we will continue to hold and own over the next several years. We also decided to accelerate the exit strategy for the investment in a distribution company in Panama and expect to complete the sale by mid-to-late 2003. Finally, there was an other than temporary decline in value in our equity method Bolivian investment due to a deterioration in our investment's position in the Bolivian capacity market.

•

Our financial investments business recorded a $2.8 million after-tax, or $.02 per share, reduction of its investment in an aircraft due to the decline in value of used airplanes as a result of the September 11, 2001 terrorist attacks and the general downturn in the aviation industry.

        We discuss these special costs further in Note 2.

        In addition, our financial investments business had lower earnings due to declining equity values and lower gains on sales of equity securities, partially offset by an $8.5 million after-tax, or $.05 per share, gain for the cumulative effect of adopting SFAS No. 133 in the first quarter of 2001. The gains on sales of securities include a $9.0 million after-tax gain on the sale of one million shares of the Orion investment in 2001 and a $9.5 million after-tax gain on the sale of two million shares of our Orion investment in 2000.

        Net income from our other nonregulated businesses increased during 2000 compared to 1999 mostly because of better market performance of certain of our financial investments including the sale of certain equity securities. In addition, in 1999, we reduced the values of a financial investment, our investment in an electric generating company in Bolivia, and certain senior-living facilities, which had negative impacts in that year, as discussed in more detail in Note 2. These increases were offset partially by lower earnings from our Latin American operation primarily due to increased operating expenses in Guatemala in 2000.

        As previously discussed in the Events of 2001 section, we decided to sell certain non-core assets and accelerate the exit strategies on other assets that we will continue to hold and own over the next several years. These assets include approximately 1,300 acres of land holdings in various stages of development located in seven sites in the central Maryland region, an operating waste water treatment plant located in Anne Arundel County, Maryland, all of our 18 senior-living facilities, and certain international power projects. While our intent is to dispose of these assets, market conditions and other events beyond our control may affect the actual sale of these assets. In

42

addition, a future decline in the fair value of these assets could result in additional losses.

        Our remaining projects are partially or substantially developed. Our strategy is to hold and in some cases further develop these projects to increase their value. However, if we were to sell these projects in the current market, we may have losses that could be material, although the amount of the losses is hard to predict.

Consolidated Nonoperating Income and Expenses

Fixed Charges

Total fixed charges decreased $32.6 million during 2001 compared to 2000 mostly because of lower interest rates and higher capitalized interest associated with our construction of new generating facilities. These decreases were offset partially by a higher average level of debt outstanding.

        Fixed charges increased $16.4 million during 2000 compared to 1999 mostly because we had more debt outstanding.

Income Taxes

The differences in income taxes result from a combination of the changes in income and the effective tax rate. We include an analysis of the changes in the effective tax rate in our Consolidated Statements of Income Taxes.

Financial Condition

Cash Flows

Cash provided by operations was $573.3 million in 2001 compared to $850.9 million in 2000 and $679.0 million in 1999.

        Cash used in investing activities was $1,472.7 million in 2001 compared to $1,106.5 million in 2000 and $615.1 million in 1999. The increase in 2001 compared to 2000 was mostly due to increased purchases of property, plant and equipment and other capital expenditures including $382.7 million relating to the net cash paid for the acquisition of Nine Mile Point. The increase in 2000 compared to 1999 was mostly due to substantial increases in our merchant energy capital expenditures to support our construction program.

        Cash provided by financing activities was $789.1 million in 2001 compared to $345.6 million in 2000 and cash used in financing activities of $144.9 million in 1999. The increase in 2001 compared to 2000 was mostly due to increased proceeds from the issuance of common stock, an increase in proceeds from the net issuance of short-term borrowings, and a $130.0 million decrease in common stock dividends paid. These items were partially offset by the issuance of less long-term debt and higher repayments of our long-term debt. The increase in 2000 compared to 1999 was mostly because we issued more long-term debt and common stock. This was offset partially by an increase in net maturities of short-term borrowings, and we repaid more long-term debt.

Security Ratings

Independent credit-rating agencies rate Constellation Energy's and BGE's fixed-income securities. The ratings indicate the agencies' assessment of each company's ability to pay interest, distributions, dividends, and principal on these securities. These ratings affect how much it will cost each company to sell these securities. The better the rating, the lower the cost of the securities to each company when they sell them. The factors that credit rating agencies consider in establishing Constellation Energy's and BGE's credit ratings include cash flows, liquidity, and the amount of debt as a component of total capitalization.

        All three rating agencies recently completed reviews of Constellation Energy's and BGE's ratings. FitchRatings affirmed its ratings of Constellation Energy. Standard & Poors Rating Group downgraded Constellation Energy's commercial paper from A-1 to A-2 and senior unsecured debt from A- to BBB+. In addition, Moody's Investors Service downgraded Constellation Energy's commercial paper from P-1 to P-2 and senior unsecured debt from A3 to Baa1. All Constellation Energy ratings have stable outlooks.

        Moody's Investors Service and FitchRatings recently affirmed the ratings of BGE. Standard & Poors Rating Group downgraded BGE commercial paper from A-1 to A-2, senior unsecured debt from A to BBB+, mortgage bonds from AA- to A, and Trust Originated Preferred Securities and Preference Stock from A- to BBB. All BGE ratings have stable outlooks.

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

		Standard & Poors Rating Group	Moody's Investors Service	Fitch- Ratings
Constellation Energy
	Commercial Paper	A-2	P-2	F-2
	Senior Unsecured Debt	BBB+	Baa1	A-
BGE
	Commercial Paper	A-2	P-1	F-1
	Mortgage Bonds	A	A1	A+
	Senior Unsecured Debt	BBB+	A2	A
	Trust Originated Preferred Securities and Preference Stock	BBB	Baa1	A-

Available Sources of Funding

As previously discussed in the Events of 2001 section, we decided to sell certain non-core assets to focus on our core strategies. We expect to use the proceeds from these sales to reduce our debt and fund our merchant energy business. We continuously monitor our liquidity requirements and believe that our facilities and access to the capital markets provide sufficient liquidity to meet our business requirements. We discuss our available sources of funding in more detail below.

43

Constellation Energy

Constellation Energy has a commercial paper program where it can issue short-term notes to fund its subsidiaries. To support its commercial paper program, Constellation Energy maintains two 364-day revolving credit agreements totaling $2.9 billion maturing in June 2002, as well as a $188.5 million multi-year revolving credit facility. Two of these facilities can also issue letters of credit. As of December 31, 2001, Constellation Energy had $246 million in outstanding letters of credit and $955 million of outstanding commercial paper which results in approximately $1.8 billion of unused credit facilities. Constellation Energy also has access to interim lines of credit as required from time to time to support its outstanding commercial paper. We expect to refinance the majority of our outstanding short-term debt during the first half of 2002 with long-term debt.

BGE

BGE maintains $168.0 million in annual committed bank lines of credit and has $75.0 million in bank revolving credit agreements to support the commercial paper program. As of December 31, 2001, BGE had no outstanding commercial paper, which results in $243.0 million in unused credit facilities. BGE also has access to interim lines of credit as required from time to time to support its outstanding commercial paper and maintains a program to sell receivables up to $25 million.

Other Nonregulated Businesses

BGE Home Products & Services maintains a program to sell receivables up to $50 million. ComfortLink has a revolving credit agreement totaling $50 million to provide liquidity for short-term financial needs.

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

Capital Resources

Our business requires a great deal of capital. Our actual consolidated capital requirements for the years 1999 through 2001, along with the estimated annual amounts for the years 2002 through 2003, are shown in the table below.

        We will continue to have cash requirements for:

•

working capital needs including the payments of interest, distributions, and dividends,

•

capital expenditures, and

•

the retirement of debt and redemption of preference stock.

        Capital requirements for 2002 through 2003 include estimates of spending for existing and anticipated projects. We continuously review and modify those estimates.

        Actual requirements may vary from the estimates included in the table below because of a number of factors including:

•

regulation, legislation, and competition,

•

BGE load requirements,

•

environmental protection standards,

•

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

•

the effect of market conditions on those projects,

•

the cost and availability of capital, and

•

the availability of cash from operations.

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

        Effective July 1, 2000, we transferred all of BGE's generation assets to nonregulated subsidiaries of Constellation Energy. The discussion and table for capital requirements below include these generation assets as part of the utility's regulated electric business through June 30, 2000. After that date, the capital requirements are included in the merchant energy business.

			1999		2000			2001		2002		2003
			(In millions)
Nonregulated Capital Requirements:
	Merchant Energy
		Construction program	$	86	$	537		$	697	$	152	$	—
		Steam generators		—		21			53		91		65
		Nine Mile Point acquisition		—		—			771		—		—
		Environmental controls		—		45			89		69		16
		Continuing requirements (including nuclear fuel)		77		96	*		205		243		199
	Total Merchant Energy capital requirements			163		699			1,815		555		280
	Other Nonregulated capital requirements			115		131			35		39		34
	Total Nonregulated capital requirements			278		830			1,850		594		314
Utility Capital Requirements:
	Regulated electric
		Generation (including nuclear fuel)		117		73			—		—		—
		Steam generators		34		13			—		—		—
		Environmental controls		31		17			—		—		—
		Transmission and distribution		185		187			180		174		174
	Total regulated electric			367		290			180		174		174
	Regulated gas			69		60			59		56		56
	Total Utility capital requirements			436		350			239		230		230
Total capital requirements			$	714	$	1,180		$	2,089	$	824	$	544

*Effective July 1, 2000, includes $44.6 million for electric generation and nuclear fuel formerly part of BGE's regulated electric business.

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Capital Requirements

Merchant Energy Business

Our merchant energy business will require additional funding for constructing planned power projects and growing its power marketing operation. These capital requirements include:

•

Construction expenditures for approximately 2,900 megawatts of natural gas-fired peaking and combined cycle production facilities in various regions of North America under construction.

•

Cost for replacing the steam generators at Calvert Cliffs. In March 2000, we received a license extension from the NRC that extends Calvert Cliffs' operating licenses to 2034 for Unit 1 and 2036 for Unit 2. Replacement of the steam generators will allow us to operate these units through our operating license periods. We expect the steam generator replacement to occur during the 2002 refueling outage for Unit 1 and during the 2003 refueling outage for Unit 2.

•

Construction expenditures for improvements to generating plants, including costs of complying with Environmental Protection Agency (EPA), Maryland and Pennsylvania nitrogen oxides emissions (NOx) regulations. We discuss the NOx regulations and timing of expenditures in Note 11.

        The table on the previous page does not include the financing for the High Desert 750 megawatt gas-fired generation project in California, which is under an operating lease with a term through February 2006. As an operating lease, we do not record any assets or debt associated with the project in our Consolidated Balance Sheets. We are leasing the project and supervising its construction.

        Under the terms of the lease, we are required to make payments that represent all or a portion of the lease balance if one of the following events occurs: termination of construction prior to completion or our default under the lease.

        Under certain circumstances, we may be required to either post cash collateral equal to the outstanding lease balance or we may elect to purchase the property for the outstanding lease balance. At any time during the term of the lease we have the right to pay off the lease and acquire the asset from the lessor. At December 31, 2001, the outstanding lease balance plus other committed expenses was $271.2 million.

        At the conclusion of the lease term in 2006, we have the following options:

•

renew the lease upon approval of the lessors,

•

elect to purchase the property for a price equal to the lease balance at the end of the term, or

•

request the lessor to sell the property.

        If we request the lessor to sell the property, we guarantee the sale proceeds up to approximately 83% of the lease balance. The lease balance at the end of the term is currently estimated to be $600 million, which represents the estimated cost of the project; however, this may vary based on the ultimate cost of construction and interest incurred during the construction period.

Regulated Electric and Gas

Regulated electric and gas construction expenditures primarily include new business construction needs and improvements to existing facilities.

Funding for Capital Requirements

Merchant Energy Business

Funding for the expansion of our merchant energy business is expected from internally generated funds, commercial paper issuances, issuances of long-term debt and equity, leases, and other financing instruments issued by Constellation Energy and its subsidiaries. Specifically related to the Nine Mile Point acquisition, approximately one-half of the purchase price was paid in November 2001, and the remainder is being financed through the sellers in a note to be repaid over five years with an interest rate of 11.0%. This note may be prepaid at any time without penalty. We closed the transaction using existing credit facilities. In addition, we also used existing credit facilities to pay Goldman Sachs a total of $355 million. This represented $196.7 million to terminate the power business services agreement with our power marketing operation and $159 million previously recognized as a payable for services rendered.

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

        Longer term, we expect to fund our growth and operating objectives primarily with internally generated funds supplemented, if necessary, by a mixture of debt and equity with an overall goal of maintaining an investment grade credit profile.

BGE

Funding for utility capital expenditures is expected from internally generated funds. During 2002 and 2003, we expect our regulated utility business to provide at least 140% of the cash needed to meet the capital requirements for its operations, excluding cash needed to retire debt. If necessary, additional funding may be obtained from commercial paper issuances, available capacity under credit facilities, the issuance of long-term debt, trust securities, or preference stock, and/or from time to time equity contributions from Constellation Energy.

Other Nonregulated Businesses

Funding for our other nonregulated businesses is expected from internally generated funds, commercial paper issuances, issuances of long-term debt of Constellation Energy, and sales of assets. BGE Home Products & Services can continue to fund capital requirements through sales of receivables. ComfortLink has a revolving credit agreement totaling $50 million to provide liquidity for short-term financial needs.

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        Our ability to sell or liquidate assets will depend on market conditions, and we cannot give assurances that these sales or liquidations could be made. We discuss our remaining real estate projects and market conditions in the Other Nonregulated Businesses section.

Committed Amounts

Our total contractual and contingent obligations as of December 31, 2001 are shown in the following table:

		Payments/Expiration
		Less than one year		One- three years		Four- five years		Over five years		Total
		(In millions)
Contractual Obligations
	Short-term borrowings	$	975.0	$	—	$	—	$	—	$	975.0
	Nonregulated long-term debt		720.4		169.8		456.8		357.1		1,704.1
	BGE long-term debt		519.8		441.0		511.8		947.7		2,420.3
	BGE preference stock		—		130.0		60.0		—		190.0
	Fuel and transportation		353.1		330.0		97.9		17.7		798.7
	Purchased capacity and energy		16.4		31.5		30.1		98.5		176.5
	Operating leases		9.1		63.3		51.2		145.8		269.4
	Capital and loan commitments*		81.5		0.8		—		—		82.3
Total contractual obligations			2,675.3		1,166.4		1,207.8		1,566.8		6,616.3
Contingent Obligations
	Letters of credit		245.6		0.2		—		—		245.8
	Guarantees, net**		427.8		38.4		666.1		236.1		1,368.4
Total contingent obligations			673.4		38.6		666.1		236.1		1,614.2
Total obligations		$	3,348.7	$	1,205.0	$	1,873.9	$	1,802.9	$	8,230.5

*

Amounts are included for applicable periods in our capital requirements table.

**

Guarantees in the above table are shown net of liabilities recorded at December 31, 2001 in our Consolidated Balance Sheets.

        While we included our contingent obligations in the table above, we do not expect to fund the full amounts under the letters of credit and guarantees.

        Lease payments under the High Desert operating lease are reflected in the table above. The lease balance at the end of the lease term is currently estimated to be $600 million. This amount is included as a guarantee in the table above.

        The table above does not include the fixed payment portions of our mark-to-market energy assets and liabilities. We discuss the expected settlement terms of these contracts in the Mark-to-Market Energy Revenues section.

Liquidity Provisions

We have certain agreements that contain provisions that would require additional collateral upon significant decreases in the Senior Unsecured Debt credit ratings of Constellation Energy. Decreases in Constellation Energy's credit ratings would not trigger an early payment on any of our credit facilities. However, if Constellation Energy's credit ratings were to fall three or more rating levels from our present rating to a level below investment grade, we would have collateral obligations of $470 million under our current contractual obligations related to our power marketing operation. In many cases, customers of our power marketing operation rely on the creditworthiness of Constellation Energy. A decline below investment grade by Constellation Energy would negatively impact the business prospects of that operation.

        The credit facilities of Constellation Energy and BGE have limited material adverse change clauses that only consider a material change in financial condition and are not directly affected by decreases in credit ratings. If these clauses are violated, the lending institutions can decline making new advances or issuing new letters of credit, but cannot accelerate existing amounts outstanding. The credit facilities of Constellation Energy contain a provision requiring Constellation Energy to maintain a ratio of debt to capitalization equal to or less than 0.65. The long-term debt indentures of Constellation Energy and BGE do not contain material adverse change clauses or financial covenants.

        Constellation Nuclear guarantees the $388 million sellers' note to finance the acquisition of Nine Mile Point. This guarantee contains provisions that require Constellation Nuclear to maintain a net worth of at least $500 million and a ratio of current assets to current liabilities of at least 1.1. Constellation Energy is required to provide adequate support to Constellation Nuclear to meet these provisions. In addition, Constellation Energy provides credit support to Calvert Cliffs and Nine Mile Point to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants.

        We discuss our short-term borrowings in Note 8, long-term debt in Note 9, lease requirements in Note 10, and commitments and guarantees in Note 11.

46

Market Risk

We are exposed to various market risks, including changes in interest rates, certain commodity prices, credit risk, and equity prices. To manage our market risk, we may enter into various derivative instruments including swaps, forward contracts, futures contracts, and options. We discuss our market risk further in Note 1. In this section, we discuss our current market risk and the related use of derivative instruments.

Interest Rate Risk

We are exposed to changes in interest rates as a result of financing through our issuance of variable-rate and fixed-rate debt. We may use derivative instruments to manage our interest rate risks. The following table provides information about our debt obligations that are sensitive to interest rate changes:

Principal Payments and Interest Rate Detail by Contractual Maturity Date

	2002			2003			2004			2005			2006			Thereafter			Total			Fair value at Dec. 31, 2001
(Dollar amounts in millions)
Short-term debt
Variable-rate debt	$	975.0		$	–		$	–		$	–		$	–		$	–		$	975.0		$	975.0
Average interest rate		3.20	%	$	–		$	–		$	–		$	–		$	–			3.20	%
Long-term debt
Variable-rate debt	$	835.5		$	7.9		$	5.4		$	–		$	111.5		$	218.8		$	1,179.1		$	1,179.1
Average interest rate		4.31	%		3.88	%		4.45	%		–			6.11	%		3.18	%		4.27	%
Fixed-rate debt	$	404.7		$	363.8		$	233.7		$	425.3		$	431.8		$	1,086.0		$	2,945.3		$	3,069.6
Average interest rate		7.78	%		7.46	%		7.53	%		8.32	%		5.65	%		6.83	%		7.26	%

        In 2001, we entered into forward starting interest rate swap contracts to manage a portion of our interest rate exposure for anticipated long-term borrowings to refinance our outstanding commercial paper obligations and maturing long-term debt. The swaps have notional or contract amounts that total $800 million with an average rate of 4.9% and expire at the end of the first quarter of 2002. At December 31, 2001, the fair value of these swap contracts was an unrealized pre-tax gain of $36.3 million. In 2002, we entered into additional forward starting interest rate swaps with notional amounts that total $700 million. These swaps have an average rate of 5.9% and expire at the end of the first quarter of 2002.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, and other commodities.

Merchant Energy Business

Our merchant energy business is exposed to various risks in the competitive marketplace that may impact its financial results and affect our earnings. These risks include changes in commodity prices, imbalances in supply and demand, and operational risk:

•

Commodity prices—contracts for energy commodities to be purchased or delivered in the future and derivatives related to such commodities exhibit significant price volatility. We use such contracts in our merchant energy business, and if we have not hedged the associated financial exposure, this price volatility could affect our earnings.

•

Supply and demand imbalances—supply and demand imbalances can occur because of plant outages, transmission system constraints, or extreme temperatures and can cause significant volatility in energy prices. If we have to buy or sell energy, capacity, or fuel during such periods of volatility to meet fixed-price contract obligations, our earnings could be affected.

•

Operational risk—operational risk is the risk that a generating plant will not be available to produce energy. In addition, if we have to buy energy in the market to fulfill a sales requirement because a generating plant is not available to produce that energy, our earnings could be affected adversely.

        Commodity price risk arises from the potential for changes in the price of, and transportation costs for, electricity, natural gas, coal, and other commodities; the volatility of commodity prices; and changes in interest rates. A number of factors associated with the structure and operation of the electricity markets significantly influence the level and volatility of prices for energy commodities and related derivative products. These factors include:

•

seasonal daily and hourly changes in demand,

•

extreme peak demands due to weather conditions,

•

available supply resources,

•

transportation availability and reliability within and between regions,

•

procedures used to maintain the integrity of the physical electricity system during extreme conditions, and

•

changes in the nature and extent of federal and state regulations.

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

•

weather conditions,

•

market liquidity,

47

•

capability and reliability of the physical electricity and gas systems, and

•

the nature and extent of electricity deregulation.

Power Marketing

Our power marketing operation is exposed to market risk as a result of the number and size of unhedged positions it holds. The power marketing operation manages market risk on a portfolio basis, subject to established risk management policies. In order to manage market risk, the power marketing operation uses a variety of derivative and non-derivative instruments, including:

•

forward contracts, which commit us to purchase or sell energy commodities in the future;

•

futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument, or to make a cash settlement, at a specific price and future date;

•

swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined contractual (notional) quantity; and

•

option contracts, which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price.

        While some of these contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. Constellation Power Source's management uses its best estimates to determine the fair value of commodity and derivative contracts it holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors, and credit exposure. However, it is likely that future market prices could vary from those used in recording mark-to-market energy assets and liabilities, and such variations could be material.

        Constellation Power Source uses various methods, including a value at risk model, to measure its exposure to market risk from its energy trading portfolio. Value at risk is a statistical model that attempts to predict risk of loss based on historical market price volatility. Constellation Power Source calculates value at risk using a variance/covariance technique that models option positions using a linear approximation of their value. Additionally, Constellation Power Source estimates variances and correlation using historical commodity price changes over the most recent rolling three-month period. Constellation Power Source's value at risk calculation includes all mark-to-market energy assets and liabilities, including contracts for energy commodities and derivatives that result in physical settlement and contracts that require cash settlement.

        The value at risk amount represents the potential pre-tax loss in the fair value of mark-to-market energy assets and liabilities over a one-day holding period with a 99.6% confidence level. Using this confidence level, Constellation Power Source would expect a one-day change in fair value greater than or equal to the daily value at risk at least once per year. Constellation Power Source's value at risk was $18.0 million as of December 31, 2001, $13.7 million as of December 31, 2000, and $7.2 million as of December 31, 1999. The average, high, and low value at risk for the year ended December 31, 2001 were $18.0 million, $68.9 million, and $8.7 million, respectively. The high value at risk amount for the year represents certain hedge contracts entered into in anticipation of closing an offsetting transaction. When the offsetting transaction closed within several days, the value at risk amount returned to a level more representative of the average for the year.

        Due to the inherent limitations of statistical measures such as value at risk, the relative immaturity of the competitive market for electricity and related derivatives, and the seasonality of changes in market prices, the value at risk calculation may not reflect the full extent of our commodity price risk exposure. Additionally, actual changes in the value of options may differ from the value at risk calculated using a linear approximation inherent in our calculation method. As a result, actual changes in the fair value of mark-to-market energy assets and liabilities could differ from the calculated value at risk, and such changes could have a material impact on our financial results.

Generation

For 2002, we expect to use the majority of the generating capacity controlled by our merchant energy business to provide standard offer service to BGE or to be sold back to the sellers of Nine Mile Point to service their load requirements. However, beginning in July 2002, we expect approximately 1,000 megawatts of industrial customer load will move from BGE's standard offer service to market-based rates. Going forward, our merchant energy business will supply 100% of the standard offer service to BGE through June 30, 2003 and 90% from July 1, 2003 through June 30, 2006.

        As a result of declines in BGE's standard offer service load and the additional 2,900 megawatts of natural gas-fired peaking and combined cycle production facilities under construction, our generation operation has a substantial amount of generating capacity that is subject to future changes in wholesale electricity prices and has fuel requirements that are subject to future changes in coal, natural gas, and oil prices. Our power generation facilities purchase fuel under contracts or on the spot market. Fuel prices may be volatile and the price that can be obtained from power sales may not change at the same rate as changes in fuel costs. Additionally, if one or more of our generating facilities is not able to produce electricity when required due to operational factors, we may have to forego sales opportunities or fulfill fixed-price sale commitments through the operation of other more costly generating facilities or through the purchase of energy in the wholesale market at higher prices.

        As part of its overall portfolio, our power marketing operation manages the commodity price risk of our electric generation facilities including power sales, fuel purchases, emission credits, weather risk, and the market risk of outages. In order to manage this risk, our merchant energy business may enter into fixed-price derivative or non-derivative contracts to

48

hedge the variability in future cash flows from forecasted sales of electricity and purchases of fuel. 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, and

•

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

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

        Our merchant energy business has hedged more than 85% of our expected energy output and fuel purchases for 2002. The amount hedged is more than 75% for 2003.

Regulated Electric Business

Under the Restructuring Order, effective July 1, 2000, BGE's residential rates are frozen for a six-year period, and its commercial and industrial rates are frozen for four to six years. BGE entered into standard offer service arrangements with Constellation Power Source and Allegheny Energy Supply Company to provide the energy and capacity required to meet its standard offer service obligations through June 30, 2006.

Regulated Gas Business

Our regulated gas business may enter into gas futures, options, and swaps to hedge its price risk under our market-based rate incentive mechanism and our off-system gas sales program. We discuss this further in Note 1. At December 31, 2001 and 2000, our exposure to commodity price risk for our regulated gas business was not material.

Credit Risk

We are exposed to credit risk, primarily through Constellation Power Source. Credit risk is the loss that may result from a counterparty's nonperformance. Constellation Power Source uses credit policies to manage its credit risk, including utilizing an established credit approval process, monitoring counterparty limits, employing credit mitigation measures such as margin, collateral, or prepayment arrangements, and using master netting agreements. Constellation Power Source measures credit risk as the replacement cost for open energy commodity and derivative positions plus amounts owed from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where we have a legally enforceable right of setoff.

        As of December 31, 2001, approximately 85% of Constellation Power Source's mark-to-market energy assets consisted of contracts with counterparties rated investment grade by the major credit rating agencies, 5% of these assets consisted of contracts with counterparties rated below investment grade, and 10% of these assets consisted of contracts with governmental authorities which are not rated but which Constellation Power Source assesses are equivalent to investment grade based upon its internal credit ratings.

        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 the power marketing operation had contracted for), we could sustain a loss that could have a material impact on our financial results.

        Our merchant energy business sells electricity under long-term power purchase agreements to two California investor-owned utilities that were downgraded by rating agencies to below investment grade. We discuss the credit and other exposures under these agreements in the Business Environment—Other States section.

Equity Price Risk

We are exposed to price fluctuations in equity markets primarily through our financial investments business, our pension plan assets, and our nuclear decommissioning trust funds. We are required by the NRC to maintain an externally funded trust for the costs of decommissioning our nuclear power plants. We discuss our nuclear decommissioning trust funds in more detail in Note 1.

        A hypothetical 10% decrease in equity prices would result in an approximate $80 million reduction in the fair value of our financial investments that are classified as trading or available-for-sale securities, excluding our investment in Orion. In 2001, the value of our pension plan assets decreased by $42.7 million due to declines in the markets in which plan assets are invested. We describe our financial investments in more detail in Note 4, and our pension plans in Note 7.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

The information required by this item with respect to market risk is set forth in Item 7 of Part II of this Form 10-K under the heading Market Risk.

49

Item 8. Financial Statements and Supplementary Data

REPORT OF MANAGEMENT

The management of the Companies is responsible for the information and representations in the Companies' financial statements. The Companies prepare the financial statements in accordance with accounting principles generally accepted in the United States of America based upon available facts and circumstances and management's best estimates and judgments of known conditions.

        The Companies maintain an accounting system and related system of internal controls designed to provide reasonable assurance that the financial records are accurate and that the Companies' assets are protected. The Companies' staff of internal auditors, which reports directly to the Chief Executive Officer, conducts periodic reviews to maintain the effectiveness of internal control procedures. PricewaterhouseCoopers LLP, independent accountants, audit the financial statements and express their opinion on them. They perform their audit in accordance with auditing standards generally accepted in the United States of America.

        The Audit Committee of the Board of Directors, which consists of three outside Directors, meets periodically with management, internal auditors, and PricewaterhouseCoopers LLP to review the activities of each in discharging their responsibilities. The internal audit staff and PricewaterhouseCoopers LLP have free access to the Audit Committee.

Mayo A. Shattuck III President and Chief Executive Officer	E. Follin Smith Senior Vice-President & Chief Financial Officer

REPORT OF INDEPENDENT ACCOUNTANTS

To the Shareholders of Constellation Energy Group, Inc. and Baltimore Gas and Electric Company

In our opinion, the consolidated financial statements listed in the index appearing under Item 14(a) 1. present fairly, in all material respects, the financial position of Constellation Energy Group, Inc. and Subsidiaries and of Baltimore Gas and Electric Company and Subsidiaries at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 14(a) 2. of this Form 10-K presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Companies' management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        We have also previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheets and statement of capitalization of Constellation Energy Group, Inc. and Subsidiaries and of Baltimore Gas and Electric Company and Subsidiaries as of December 31, 1999, 1998 and 1997, and the related consolidated statements of income, comprehensive income, cash flows, common shareholders' equity and income taxes for the years ended December 31, 1998 and 1997 (none of which are presented herein); and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the Summary of Operations and Summary of Financial Condition of Constellation Energy Group, Inc. included in the Selected Financial Data for each of the five years in the period ended December 31, 2001, and the information set forth in the Summary of Operations and Summary of Financial Condition of Baltimore Gas and Electric Company included in the Selected Financial Data for each of the five years in the period ended December 31, 2001, is fairly stated, in all material respects, in relation to the consolidated financial statements from which it has been derived.

        As discussed in Note 1 to the consolidated financial statements, the Companies changed their method of accounting for derivative and hedging activities pursuant to Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by Statement of Financial Accounting Standards No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities (an amendment of FASB Statement No. 133).

PricewaterhouseCoopers LLP
Baltimore, Maryland
January 21, 2002

50

CONSOLIDATED STATEMENTS OF INCOME

Constellation Energy Group, Inc. and Subsidiaries

Year Ended December 31,		2001			2000			1999
		(In millions, except per share amounts)
Revenues
	Nonregulated revenues	$	1,214.4		$	1,114.0		$	1,105.6
	Regulated electric revenues		2,039.6			2,134.7			2,258.8
	Regulated gas revenues		674.3			603.8			476.5
	Total revenues		3,928.3			3,852.5			3,840.9
Expenses
	Operating expenses		2,392.2			2,311.4			2,339.6
	Workforce reduction costs		105.7			7.0			—
	Contract termination related costs		224.8			—			—
	Impairment losses and other costs		202.1			—			64.3
	Depreciation and amortization		419.1			470.0			449.8
	Taxes other than income taxes		226.6			221.5			227.3
	Total expenses		3,570.5			3,009.9			3,081.0
Income from Operations			357.8			842.6			759.9
Other Income			1.3			4.2			7.9
Income Before Fixed Charges and Income Taxes			359.1			846.8			767.8
Fixed Charges
	Interest expense		283.2			282.4			248.0
	Interest capitalized and allowance for borrowed funds used during construction		(57.6	)		(24.2	)		(6.5	)
	BGE preference stock dividends		13.2			13.2			13.5
	Total fixed charges		238.8			271.4			255.0
Income Before Income Taxes			120.3			575.4			512.8
Income Taxes			37.9			230.1			186.4
Income Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle			82.4			345.3			326.4
Extraordinary Loss, Net of Income Taxes of $30.4 (see Note 5)			—			—			(66.3	)
Cumulative Effect of Change in Accounting Principle, Net of Income Taxes of $5.6 (see Note 1)			8.5			—			—
Net Income		$	90.9		$	345.3		$	260.1
Earnings Applicable to Common Stock		$	90.9		$	345.3		$	260.1
Average Shares of Common Stock Outstanding			160.7			150.0			149.6
Earnings Per Common Share and Earnings Per Common Share—Assuming Dilution Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle		$	.52		$	2.30		$	2.18
Extraordinary Loss			—			—			(.44	)
Cumulative Effect of Change in Accounting Principle			.05			—			—
Earnings Per Common Share and Earnings Per Common Share—Assuming Dilution		$	.57		$	2.30		$	1.74

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Constellation Energy Group, Inc. and Subsidiaries

Year Ended December 31,		2001			2000		1999
		(In millions)
Net Income		$	90.9		$	345.3	$	260.1
Other comprehensive income, net of taxes
	Financial securities		124.5			18.6		3.9
	Hedging instruments		102.6			—		—
	Minimum pension liability		(44.7	)		—		—
Comprehensive Income Before Cumulative Effect of Change in Accounting Principle			273.3			363.9		264.0
Cumulative Effect of Change in Accounting Principle, Net of Income Taxes of $22.6			(35.5	)		—		—
Comprehensive Income		$	237.8		$	363.9	$	264.0

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

51

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

At December 31,				2001			2000
				(In millions)
Assets
	Current Assets
		Cash and cash equivalents		$	72.4		$	182.7
		Accounts receivable (net of allowance for uncollectibles of $22.8 and $21.3, respectively)			738.9			792.6
		Trading securities			178.2			189.3
		Mark-to-market energy assets			398.4			453.1
		Fuel stocks			108.0			78.2
		Materials and supplies			196.3			151.3
		Prepaid taxes other than income taxes			93.4			73.5
		Other			74.6			52.8
		Total current assets			1,860.2			1,973.5
	Investments and Other Assets
		Real estate projects and investments			210.7			290.3
		Investments in power projects			499.1			510.6
		Investment in Orion Power Holdings, Inc.			442.5			192.0
		Financial investments			60.7			161.0
		Nuclear decommissioning trust funds			683.5			228.7
		Net pension asset			—			93.2
		Mark-to-market energy assets			1,819.8			2,069.3
		Other			207.4			123.0
		Total investments and other assets			3,923.7			3,668.1
	Property, Plant and Equipment
		Regulated property, plant and equipment
			Plant in service		4,862.4			4,780.3
			Construction work in progress		81.8			75.3
			Plant held for future use		4.5			4.5
			Total regulated property, plant and equipment		4,948.7			4,860.1
		Nonregulated generation property, plant and equipment			6,551.1			5,286.8
		Other nonregulated property, plant and equipment			192.9			147.0
		Nuclear fuel (net of amortization)			169.5			128.3
		Accumulated depreciation			(4,161.8	)		(3,756.7	)
		Net property, plant and equipment			7,700.4			6,665.5
	Deferred Charges
		Regulatory assets (net)			463.8			514.9
		Other			129.5			117.3
		Total deferred charges			593.3			632.2
	Total Assets			$	14,077.6		$	12,939.3

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

52

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

At December 31,			2001		2000
			(In millions)
Liabilities and Capitalization
	Current Liabilities
		Short-term borrowings	$	975.0	$	243.6
		Current portion of long-term debt		1,406.7		906.6
		Accounts payable		534.4		750.0
		Mark-to-market energy liabilities		323.3		358.2
		Dividends declared		23.0		66.5
		Other		297.1		250.8
		Total current liabilities		3,559.5		2,575.7
	Deferred Credits and Other Liabilities
		Deferred income taxes		1,431.0		1,353.2
		Mark-to-market energy liabilities		1,476.5		1,636.3
		Net pension liability		173.3		—
		Postretirement and postemployment benefits		330.9		265.2
		Deferred investment tax credits		93.4		101.4
		Other		266.9		484.2
		Total deferred credits and other liabilities		3,772.0		3,840.3
	Capitalization
		Long-term debt		2,712.5		3,159.3
		BGE preference stock not subject to mandatory redemption		190.0		190.0
		Common shareholders' equity		3,843.6		3,174.0
		Total capitalization		6,746.1		6,523.3
	Commitments, Guarantees, and Contingencies (see Note 11)
	Total Liabilities and Capitalization		$	14,077.6	$	12,939.3

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

53

CONSOLIDATED STATEMENTS OF CASH FLOWS

Constellation Energy Group, Inc. and Subsidiaries

Year Ended December 31,			2001			2000			1999
			(In millions)
Cash Flows From Operating Activities
	Net income		$	90.9		$	345.3		$	260.1
	Adjustments to reconcile to net cash provided by operating activities
		Cumulative effect of change in accounting principle		(8.5	)		—			—
		Extraordinary loss		—			—			66.3
		Depreciation and amortization		468.9			524.8			505.9
		Deferred income taxes		(26.5	)		42.1			13.0
		Investment tax credit adjustments		(8.1	)		(8.4	)		(8.6	)
		Deferred fuel costs		37.6			2.8			(61.1	)
		Accrued pension and postemployment benefits		55.3			27.9			36.1
		Gain on sale of investments		(40.7	)		(64.1	)		—
		Loss (gain) on sale of subsidiaries and plant assets		43.3			(13.3	)		—
		Deregulation transition cost		—			24.0			—
		Workforce reduction costs		105.7			7.0			—
		Contract termination related costs		26.2			—			—
		Impairment losses and other costs		158.7			—			64.3
		Equity in earnings of affiliates and joint ventures (net)		2.0			(5.3	)		(7.6	)
		Changes in mark-to-market energy assets and liabilities		109.5			(379.6	)		(114.3	)
		Changes in other current assets		(57.7	)		(230.7	)		(216.4	)
		Changes in other current liabilities		(218.8	)		406.2			121.0
		Other		(164.5	)		172.2			20.3
	Net cash provided by operating activities			573.3			850.9			679.0
Cash Flows From Investing Activities
	Purchases of property, plant and equipment and other capital expenditures			(1,318.3	)		(1,079.0	)		(616.5	)
	Acquisition of Nine Mile Point			(382.7	)		—			—
	Sale of (investment in) Orion			26.2			(101.5	)		(97.7	)
	Contributions to nuclear decommissioning trust funds			(22.0	)		(13.2	)		(17.6	)
	Purchases of marketable equity securities			(33.2	)		(80.8	)		(27.3	)
	Sales of marketable equity securities			132.6			110.2			34.9
	Proceeds from the sale of property, plant, and equipment			112.0			20.8			—
	Other investments			12.7			37.0			109.1
	Net cash used in investing activities			(1,472.7	)		(1,106.5	)		(615.1	)
Cash Flows From Financing Activities
	Net issuance (maturity) of short-term borrowings			731.4			(127.9	)		371.5
	Proceeds from issuance of
		Long-term debt		1,175.2			1,374.0			302.8
		Common stock		504.4			35.9			9.6
	Repayment of long-term debt			(1,510.2	)		(697.0	)		(584.4	)
	Redemption of preference stock			—			—			(7.0	)
	Common stock dividends paid			(120.7	)		(250.7	)		(251.1	)
	Other			9.0			11.3			13.7
	Net cash provided by (used in) financing activities			789.1			345.6			(144.9	)
Net (Decrease) Increase in Cash and Cash Equivalents				(110.3	)		90.0			(81.0	)
Cash and Cash Equivalents at Beginning of Year				182.7			92.7			173.7
Cash and Cash Equivalents at End of Year			$	72.4		$	182.7		$	92.7
Other Cash Flow Information:
	Cash paid during the year for:
		Interest (net of amounts capitalized)	$	238.3		$	268.2		$	245.3
		Income taxes	$	101.5		$	184.7		$	165.6
Non-Cash Transaction:
	In connection with our purchase of Nine Mile Point, the fair value of the net assets purchased was $770.8 million. We paid $382.7 million in cash, including settlement costs, and incurred a sellers' note of $388.1 million as discussed further in Note 14.

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

54

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY

Constellation Energy Group, Inc. and Subsidiaries

								Accumulated Other Comprehensive Income
Years Ended December 31, 2001, 2000, and 1999	Common Stock				Retained Earnings						Total Amount
	Shares	Amount
	(Dollar amounts in millions, number of shares in thousands)
Balance at December 31, 1998	149,246	$	1,485.1		$	1,490.3		$	20.5		$	2,995.9
Net income						260.1						260.1
Common stock dividend declared ($1.68 per share)						(251.3	)					(251.3	)
Common stock issued	310		9.6									9.6
Other			(0.7	)								(0.7	)
Net unrealized gain on securities, net of taxes of $3.2									3.9			3.9
Balance at December 31, 1999	149,556		1,494.0			1,499.1			24.4			3,017.5
Net income						345.3						345.3
Common stock dividend declared ($1.68 per share)						(251.8	)					(251.8	)
Common stock issued	976		35.9									35.9
Other			8.8			(0.3	)					8.5
Net unrealized gain on securities, net of taxes of $9.5									18.6			18.6
Balance at December 31, 2000	150,532		1,538.7			1,592.3			43.0			3,174.0
Net income						90.9						90.9
Common stock dividend declared ($.48 per share)						(77.1	)					(77.1	)
Common stock issued	13,176		504.4									504.4
Other			(0.9	)		5.4						4.5
Cumulative effect of change in accounting principle, net of taxes of $22.6									(35.5	)		(35.5	)
Net unrealized gain on securities, net of taxes of $71.8									124.5			124.5
Net unrealized gain on hedging instruments, net of taxes of $65.6									102.6			102.6
Minimum pension liability, net of taxes of $29.3									(44.7	)		(44.7	)
Balance at December 31, 2001	163,708	$	2,042.2		$	1,611.5		$	189.9		$	3,843.6

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

55

CONSOLIDATED STATEMENTS OF CAPITALIZATION

Constellation Energy Group, Inc. and Subsidiaries

At December 31,				2001			2000
				(In millions)
Long-Term Debt
	Long-term debt of Constellation Energy
		77/8% Notes, due April 1, 2005		$	300.0		$	300.0
		Floating rate notes, due April 4, 2003			—			200.0
		Extendible notes, due June 21, 2010			—			300.0
		Floating rate reset notes, due March 15, 2002			—			200.0
		Floating rate notes, due January 17, 2002			635.0			—
		Total long-term debt of Constellation Energy			935.0			1,000.0
	Long-term debt of nonregulated businesses
		Tax-exempt debt transferred from BGE effective July 1, 2000
			Pollution control loan, due July 1, 2011		36.0			36.0
			Port facilities loan, due June 1, 2013		48.0			48.0
			Adjustable rate pollution control loan, due July 1, 2014		20.0			20.0
			5.55% Pollution control revenue refunding loan, due July 15, 2014		47.0			47.0
			Economic development loan, due December 1, 2018		35.0			35.0
			6.00% Pollution control revenue refunding loan, due April 1, 2024		75.0			75.0
			Floating rate pollution control loan, due June 1, 2027		8.8			8.8
			51/2% Installment series, due July 15, 2002		6.7			7.6
		District Cooling facilities loan, due December 1, 2031			25.0			—
		Loans under revolving credit agreements			46.0			34.0
		11% Installment note, due November 7, 2006			388.1			—
		Mortgage and construction loans
			Floating rate mortgage notes and construction loans, due through 2005		13.8			51.3
			Other mortgage notes ranging from 4.25% to 9.65% due March 15, 2009 to November 1, 2033		19.7			20.3
		Unsecured notes			—			287.0
		Total long-term debt of nonregulated businesses			769.1			670.0
	First Refunding Mortgage Bonds of BGE
		83/8% Series, due August 15, 2001			—			122.2
		71/4% Series, due July 1, 2002			124.0			124.0
		61/2% Series, due February 15, 2003			124.8			124.8
		61/8% Series, due July 1, 2003			124.9			124.9
		51/2% Series, due April 15, 2004			125.0			125.0
		Remarketed floating rate series, due September 1, 2006			111.5			111.5
		71/2% Series, due January 15, 2007			123.5			123.5
		65/8% Series, due March 15, 2008			124.9			124.9
		71/2% Series, due March 1, 2023			98.1			109.9
		71/2% Series, due April 15, 2023			84.0			84.0
		Total First Refunding Mortgage Bonds of BGE			1,040.7			1,174.7
	Other long-term debt of BGE
		5.25% Notes, due December 15, 2006			300.0			—
		Floating rate reset notes, due February 5, 2002			200.0			—
		Floating rate reset notes, due October 19, 2001			—			200.0
		Medium-term notes, Series B			23.1			23.1
		Medium-term notes, Series C			25.5			25.5
		Medium-term notes, Series D			68.0			128.0
		Medium-term notes, Series E			200.0			200.0
		Medium-term notes, Series G			140.0			200.0
		Medium-term notes, Series H			—			27.0
		6.75% Remarketable or redeemable securities, due December 15, 2012			173.0			173.0
		Total other long-term debt of BGE			1,129.6			976.6
	BGE obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% deferrable interest subordinated debentures due June 30, 2038				250.0			250.0
Unamortized discount and premium					(5.2	)		(5.4	)
Current portion of long-term debt					(1,406.7	)		(906.6	)
Total long-term debt				$	2,712.5		$	3,159.3

See Notes to Consolidated Financial Statements.

continued on next page

56

CONSOLIDATED STATEMENTS OF CAPITALIZATION

Constellation Energy Group, Inc. and Subsidiaries

At December 31,			2001		2000
			(In millions)
BGE Preference Stock
	Cumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized
		7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003	$	40.0	$	40.0
		6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003		50.0		50.0
		6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004		40.0		40.0
		6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005		60.0		60.0
		Total preference stock not subject to mandatory redemption		190.0		190.0
Common Shareholders' Equity
	Common stock without par value, 250,000,000 shares authorized; 163,707,950 and 150,531,716 shares issued and outstanding at December 31, 2001 and 2000, respectively. (At December 31, 2001 11,797,976 shares were reserved for the Shareholder Investment Plan and 6,000,000 were reserved for the long-term incentive plans.)			2,042.2		1,538.7
	Retained earnings			1,611.5		1,592.3
	Accumulated other comprehensive income			189.9		43.0
	Total common shareholders' equity			3,843.6		3,174.0
	Total Capitalization		$	6,746.1	$	6,523.3

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

57

CONSOLIDATED STATEMENTS OF INCOME TAXES

Constellation Energy Group, Inc. and Subsidiaries

Year Ended December 31,				2001			2000			1999
				(Dollar amounts in millions)
Income Taxes
	Current
		Federal		$	45.5		$	148.2		$	176.3
		State			27.0			48.2			5.7
	Current taxes charged to expense				72.5			196.4			182.0
	Deferred
		Federal			(22.4	)		53.9			5.8
		State			(4.1	)		(11.8	)		7.2
	Deferred taxes charged to expense				(26.5	)		42.1			13.0
	Investment tax credit adjustments				(8.1	)		(8.4	)		(8.6	)
	Income taxes per Consolidated Statements of Income			$	37.9		$	230.1		$	186.4
Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes
	Income before income taxes (excluding BGE preference stock dividends)			$	133.5		$	588.6		$	526.3
		Statutory federal income tax rate			35	%		35	%		35	%
		Income taxes computed at statutory federal rate			46.7			206.0			184.2
		Increases (decreases) in income taxes due to
			Depreciation differences not normalized on regulated activities		5.6			12.6			15.3
			Allowance for equity funds used during construction		(1.1	)		(0.9	)		(2.2	)
			Amortization of deferred investment tax credits		(8.1	)		(8.4	)		(8.6	)
			Tax credits flowed through to income		(13.4	)		(6.5	)		(3.2	)
			Amortization of deferred tax rate differential on regulated activities		(2.1	)		(2.9	)		(3.0	)
			State income taxes, net of federal income tax benefit		13.5			31.7			8.2
			Other		(3.2	)		(1.5	)		(4.3	)
		Total income taxes		$	37.9		$	230.1		$	186.4
		Effective income tax rate			28.4	%		39.1	%		35.4	%

At December 31,			2001		2000
			(Dollar amounts in millions)
Deferred Income Taxes
	Deferred tax liabilities
		Net property, plant and equipment	$	1,156.0	$	1,135.5
		Income taxes recoverable through future rates		31.4		32.8
		Deferred termination and postemployment costs		7.0		13.6
		Deferred fuel costs		11.7		24.9
		Power marketing and risk management activities		776.4		819.4
		Deferred electric generation-related regulatory assets		87.1		93.7
		Financial investments and hedging instruments		153.9		42.6
		Other		140.9		135.6
		Total deferred tax liabilities		2,364.4		2,298.1
	Deferred tax assets
		Accrued pension and postemployment benefit costs		132.7		76.5
		Deferred investment tax credits		35.1		35.5
		Nuclear decommissioning liability		32.1		28.2
		Power marketing and risk management activities		549.1		638.2
		Reduction of investments		82.3		29.8
		Other		102.1		136.7
		Total deferred tax assets		933.4		944.9
	Deferred tax liability, net		$	1,431.0	$	1,353.2

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

58

CONSOLIDATED STATEMENTS OF INCOME

Baltimore Gas and Electric Company and Subsidiaries

Year Ended December 31,			2001			2000			1999
			(In millions)
Revenues
	Electric revenues		$	2,040.0		$	2,135.2		$	2,259.5
	Gas revenues			680.7			611.6			485.3
	Nonregulated revenues			—			—			347.4
	Total revenues			2,720.7			2,746.8			3,092.2
Expenses
	Operating Expenses:
		Electric fuel and purchased energy		1,192.8			870.7			486.8
		Gas purchased for resale		401.3			350.6			233.7
		Operations and maintenance		363.0			547.4			728.8
		Workforce reduction costs		57.0			7.0			—
		Nonregulated—selling, general, and administrative		—			—			286.0
	Depreciation and amortization			221.0			366.1			427.9
	Taxes other than income taxes			173.8			192.6			224.7
	Total expenses			2,408.9			2,334.4			2,387.9
Income from Operations				311.8			412.4			704.3
Other Income				0.4			7.5			8.4
Income Before Fixed Charges and Income Taxes				312.2			419.9			712.7
Fixed Charges
	Interest expense (net)			156.2			187.2			209.7
	Allowance for borrowed funds used during construction			(1.6	)		(3.2	)		(3.8	)
	Total fixed charges			154.6			184.0			205.9
Income Before Income Taxes				157.6			235.9			506.8
Income Taxes
	Current			62.4			142.1			192.1
	Deferred			0.2			(44.4	)		(5.2	)
	Investment tax credit adjustments			(2.3	)		(5.3	)		(8.5	)
	Total income taxes			60.3			92.4			178.4
Income Before Extraordinary Item				97.3			143.5			328.4
Extraordinary Loss, Net of Income Taxes of $30.4 (see Note 5)				—			—			(66.3	)
Net Income				97.3			143.5			262.1
Preference Stock Dividends				13.2			13.2			13.5
Earnings Applicable to Common Stock			$	84.1		$	130.3		$	248.6

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Baltimore Gas and Electric Company and Subsidiaries

Year Ended December 31,	2001		2000		1999
	(In millions)
Net Income	$	97.3	$	143.5	$	262.1
Other comprehensive loss, net of taxes		—		—		(3.4	)
Comprehensive Income	$	97.3	$	143.5	$	258.7

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

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CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

At December 31,				2001			2000
				(In millions)
Assets
	Current Assets
		Cash and cash equivalents		$	37.4		$	21.3
		Accounts receivable (net of allowance for uncollectibles of $13.4)			295.2			413.0
		Accounts receivable, affiliated companies			572.5			8.2
		Note receivable, affiliated company			—			87.0
		Fuel stocks			52.3			34.1
		Materials and supplies			33.1			37.3
		Prepaid taxes other than income taxes			72.5			44.9
		Other			7.6			4.7
		Total current assets			1,070.6			650.5
	Investments and Other Assets
		Net pension asset			—			100.2
		Receivable, affiliated company			113.3			125.0
		Other			74.5			68.7
		Total investments and other assets			187.8			293.9
	Utility Plant
		Plant in service
			Electric		3,349.9			3,259.0
			Gas		1,014.4			988.4
			Common		498.1			532.9
			Total plant in service		4,862.4			4,780.3
		Accumulated depreciation			(1,751.4	)		(1,700.3	)
		Net plant in service			3,111.0			3,080.0
		Construction work in progress			81.8			75.3
		Plant held for future use			4.5			4.5
		Net utility plant			3,197.3			3,159.8
	Deferred Charges
		Regulatory assets (net)			463.8			514.9
		Other			35.0			35.1
		Total deferred charges			498.8			550.0
	Total Assets			$	4,954.5		$	4,654.2

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

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CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

At December 31,			2001			2000
			(In millions)
Liabilities and Capitalization
	Current Liabilities
		Short-term borrowings	$	—		$	32.1
		Current portions of long-term debt		666.3			567.6
		Accounts payable		63.6			119.3
		Accounts payable, affiliated companies		92.6			103.5
		Customer deposits		50.0			44.4
		Accrued taxes		7.6			25.0
		Accrued interest		37.0			43.4
		Accrued vacation costs		21.7			20.8
		Other		39.2			29.6
		Total current liabilities		978.0			985.7
	Deferred Credits and Other Liabilities
		Deferred income taxes		503.1			508.7
		Postretirement and postemployment benefits		266.1			231.2
		Deferred investment tax credits		22.7			25.0
		Decommissioning of federal uranium enrichment facilities		19.3			23.7
		Other		22.2			23.2
		Total deferred credits and other liabilities		833.4			811.8
	Long-term Debt
		First refunding mortgage bonds of BGE		1,040.7			1,174.7
		Other long-term debt of BGE		1,129.6			976.6
		Company obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% debentures of BGE due June 30, 2038		250.0			250.0
		Long-term debt of nonregulated businesses		71.0			34.0
		Unamortized discount and premium		(3.3	)		(3.3	)
		Current portion of long-term debt		(666.3	)		(567.6	)
		Total long-term debt		1,821.7			1,864.4
	Preference Stock Not Subject to Mandatory Redemption			190.0			190.0
	Common Shareholder's Equity
		Common stock		711.9			465.1
		Retained earnings		419.5			337.2
		Total common shareholder's equity		1,131.4			802.3
		Total capitalization		3,143.1			2,856.7
	Commitments, Guarantees, and Contingencies (see Note 11)
	Total Liabilities and Capitalization		$	4,954.5		$	4,654.2

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

61

CONSOLIDATED STATEMENTS OF CASH FLOWS

Baltimore Gas and Electric Company and Subsidiaries

Year Ended December 31,			2001			2000			1999
			(In millions)
Cash Flows From Operating Activities
	Net income		$	97.3		$	143.5		$	262.1
	Adjustments to reconcile to net cash provided by operating activities
		Extraordinary loss		—			—			66.3
		Depreciation and amortization		223.3			393.6			480.4
		Deferred income taxes		0.2			(44.4	)		(5.2	)
		Investment tax credit adjustments		(2.3	)		(5.3	)		(8.5	)
		Deferred fuel costs		37.6			2.8			(61.1	)
		Accrued pension and postemployment benefits		14.7			16.1			35.5
		Allowance for equity funds used during construction		(3.0	)		(2.6	)		(6.2	)
		Workforce reduction costs		57.0			7.0			—
		Equity in earnings of affiliates and joint ventures (net)		—			1.3			29.1
		Changes in mark-to-market energy assets and liabilities		—			—			(34.0	)
		Changes in other current assets		(410.6	)		(189.7	)		(15.1	)
		Changes in other current liabilities		(93.4	)		68.7			22.7
		Other		9.9			5.7			16.7
	Net cash (used in) provided by operating activities			(69.3	)		396.7			782.7
Cash Flows From Investing Activities
	Utility construction expenditures (excluding AFC)			(236.4	)		(309.5	)		(385.7	)
	Nuclear fuel expenditures			—			(39.5	)		(49.2	)
	Contributions to nuclear decommissioning trust fund			—			(8.8	)		(17.6	)
	Purchases of marketable equity securities			—			—			(9.2	)
	Sales of marketable equity securities			—			—			6.0
	Power projects			—			—			(17.9	)
	Other			(20.9	)		0.1			12.9
	Net cash used in investing activities			(257.3	)		(357.7	)		(460.7	)
Cash Flows From Financing Activities
	Net (maturity) issuance of short-term borrowings			(32.1	)		(96.9	)		129.0
	Proceeds from issuance of
		Long-term debt		532.1			377.3			257.2
		Common stock		—			—			9.6
	Reacquisition of long-term debt			(394.1	)		(121.7	)		(466.3	)
	Redemption of preference stock			—			—			(7.0	)
	Common stock dividends paid			—			—			(62.7	)
	Preferred and preference stock dividends paid			(13.2	)		(13.2	)		(13.6	)
	Distributions from (to) Constellation Energy			250.0			(188.5	)		(316.6	)
	Other			—			1.8			(1.8	)
	Net cash provided by (used in) financing activities			342.7			(41.2	)		(472.2	)
Net Increase (Decrease) in Cash and Cash Equivalents				16.1			(2.2	)		(150.2	)
Cash and Cash Equivalents at Beginning of Year				21.3			23.5			173.7
Cash and Cash Equivalents at End of Year			$	37.4		$	21.3		$	23.5
Other Cash Flow Information
	Cash paid during the year for:
		Interest (net of amounts capitalized)	$	162.0		$	184.7		$	200.2
		Income taxes	$	102.8		$	127.6		$	178.8
Noncash Investing and Financing Activities:
	On July 1, 2000, BGE transferred $1,578.4 million of generation assets, net of associated liabilities, to nonregulated affiliates of Constellation Energy pursuant to the Maryland PSC's Restructuring Order.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1 Significant Accounting Policies

Nature of Our Business

Constellation Energy Group, Inc. (Constellation Energy) is a North American energy company that conducts its business through various subsidiaries including a merchant energy business and Baltimore Gas and Electric Company (BGE). Our merchant energy business generates and markets wholesale electricity in North America. BGE is an electric and gas public transmission and distribution utility company with a service territory that covers the City of Baltimore and all or part of ten counties in central Maryland. We describe our operating segments in Note 3.

        This report 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. Reference in this report to the "utility business" is to BGE.

Consolidation Policy

We use three different accounting methods to report our investments in our subsidiaries or other companies: consolidation, the equity method, and the cost method.

Consolidation

We use consolidation when we own a majority of the voting stock of the subsidiary. This means the accounts of our subsidiaries are combined with our accounts. We eliminate intercompany balances and transactions when we consolidate these accounts.

The Equity Method

We usually use the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies (including power projects) where we hold a 20% to 50% voting interest. Under the equity method, we report:

•

our interest in the entity as an investment in our Consolidated Balance Sheets, and

•

our percentage share of the earnings from the entity in our Consolidated Statements of Income.

        The only time we do not use this method is if we can exercise control over the operations and policies of the company. If we have control, accounting rules require us to use consolidation.

The Cost Method

We usually use the cost method if we hold less than a 20% voting interest in an investment. Under the cost method, we report our investment at cost in our Consolidated Balance Sheets. The only time we do not use this method is when we can exercise significant influence over the operations and policies of the company. If we have significant influence, accounting rules require us to use the equity method.

Regulation of Utility Business

The Maryland Public Service Commission (Maryland PSC) provides the final determination of the rates we charge our customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under accounting principles generally accepted in the United States of America. However, sometimes the Maryland PSC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers. When this happens, we must defer (include as an asset or liability in our Consolidated Balance Sheets and exclude from our Consolidated Statements of Income) certain utility expenses and income as regulatory assets and liabilities. We have recorded these regulatory assets and liabilities in our Consolidated Balance Sheets in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. We summarize and discuss our regulatory assets and liabilities further in Note 6.

        In 1997, the Financial Accounting Standards Board (FASB) through its Emerging Issues Task Force (EITF) issued EITF 97-4, Deregulation of the Pricing of Electricity—Issues Related to the Application of FASB Statements No. 71 and 101. The EITF concluded that a company should cease to apply SFAS No. 71 when either legislation is passed or a regulatory body issues an order that contains sufficient detail to determine how the transition plan will affect the deregulated portion of the business. Additionally, a company would continue to recognize regulatory assets and liabilities in the Consolidated Balance Sheets to the extent that the transition plan provides for their recovery.

        On November 10, 1999, the Maryland PSC issued a Restructuring Order that we believe provided sufficient details of the transition plan to competition for BGE's electric generation business to require BGE to discontinue the application of SFAS No. 71 for that portion of its business. Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101, Regulated Enterprises—Accounting for the Discontinuation of FASB Statement No. 71 and EITF 97-4 for BGE's electric generation business. BGE's transmission and distribution business continues to meet the requirements of SFAS No. 71, as that business remains regulated. We discuss this further in Note 5.

Revenues

Nonregulated Businesses

Our subsidiary, Constellation Power Source, uses the mark-to-market method of accounting, as discussed on the next page, to account for a portion of its power marketing activities. We record all other nonregulated revenues in the period earned for services rendered, commodities or products delivered, or contracts settled. Equity in earnings from our investments in power projects is included in revenues.

63

        Power marketing activities include new origination transactions and risk management activities using contracts for energy, other energy-related commodities, and related derivative contracts. We use the mark-to-market method of accounting for portions of Constellation Power Source's activities as required by EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. Under the mark-to-market method of accounting, we record the fair value of commodity and derivative contracts as mark-to-market energy assets and liabilities at the time of contract execution. We record reserves to reflect uncertainties associated with certain estimates inherent in the determination of fair value. Mark-to-market energy revenues include:

•

the fair value of new transactions at origination,

•

unrealized gains and losses from changes in the fair value of open positions,

•

net gains and losses from realized transactions, and

•

changes in reserves.

        We record the changes in mark-to-market energy assets and liabilities on a net basis in "Nonregulated revenues" in our Consolidated Statements of Income. Mark-to-market energy assets and liabilities are comprised of a combination of energy and energy-related derivative and non-derivative contracts. While some of these contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using modeling techniques to determine expected future market prices, contract quantities, or both. The market prices used to determine fair value reflect management's best estimate considering various factors, including closing exchange and over-the-counter quotations, time value, and volatility factors. However, it is possible that future market prices could vary from those used in recording mark-to-market energy assets and liabilities, and such variations could be material.

        Certain power marketing and risk management transactions entered into under master agreements and other arrangements provide our merchant energy business with a right of setoff in the event of bankruptcy or default by the counterparty. We report such transactions net in the balance sheets in accordance with FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts.

Regulated Utility

We record utility revenues when we provide service to customers.

Fuel and Purchased Energy Costs

We incur costs for:

•

the fuel we use to generate electricity,

•

purchases of electricity from others, and

•

natural gas that we resell.

        These costs are included in "Operating expenses" in our Consolidated Statements of Income. We discuss each of these separately below.

Fuel Used to Generate Electricity and Purchases of Electricity From Others

Effective July 1, 2000, these costs are recorded as incurred. Historically and until July 1, 2000, we were allowed to recover our costs of electric fuel under the electric fuel rate clause set by the Maryland PSC. Under the electric fuel rate clause, we charged our electric customers for:

•

the fuel we use to generate electricity (nuclear fuel, coal, gas, or oil), and

•

the net cost of purchases and sales of electricity.

        We charged the actual costs of these items to customers with no profit to us. To do this, we had to keep track of what we spent and what we collected from customers under the fuel rate in a given period. Usually these two amounts were not the same because there was a difference between the time we spent the money and the time we collected it from our customers.

        Under the electric fuel rate clause, we deferred the difference between our actual costs of fuel and energy and what we collected from customers under the fuel rate in a given period. We either billed or refunded our customers that difference in the future. As a result of the Restructuring Order, the fuel rate was discontinued effective July 1, 2000. We discuss this further in Note 6.

Natural Gas

We charge our gas customers for the natural gas they purchase from us using "gas cost adjustment clauses" set by the Maryland PSC. These clauses operate similarly to the electric fuel rate clause described earlier in this note. However, the Maryland PSC approved a modification of the gas cost adjustment clauses to provide a market-based rates incentive mechanism. Under market-based rates, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers. Effective November 2001, the Maryland PSC approved an order that modifies certain provisions of the market-based rates incentive mechanism. These provisions require that BGE secure fixed-price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for the November through March period. These fixed price contracts are not subject to sharing under the market-based rates incentive mechanism.

Risk Management

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 as discussed further in Note 12. We use interest rate swaps to manage our interest rate exposures associated with new debt issuances. These swaps are designated as cash-flow hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as discussed later in this note, with our gains recorded in "Other current assets" in our Consolidated Balance Sheets and "Accumulated other comprehensive income," in our Consolidated Statements of

64

Common Shareholders' Equity and Consolidated Statements of Capitalization, in anticipation of planned financing transactions. Any gain or loss on the hedges will be reclassified from "Accumulated other comprehensive income" into "Interest expense" and be included in earnings during the periods in which the interest payments being hedged occur.

        Our merchant energy and regulated gas businesses use derivative and non-derivative instruments to manage changes in their respective commodity prices as discussed in more detail below.

Merchant Energy Business

The power marketing operation manages market risk on a portfolio basis, subject to established risk management policies. The power marketing operation uses a variety of derivative and non-derivative instruments, including:

•

forward contracts, which commit us to purchase or sell energy commodities in the future;

•

futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument, or to make a cash settlement, at a specific price and future date;

•

swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined contractual (notional) quantity; and

•

option contracts, which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price.

        As part of its overall portfolio, the power marketing operation manages the commodity price risk of our electric generation facilities, including power sales, fuel purchases, emission credits, weather risk, and the market risk of outages. In order to manage this risk, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of electricity and purchases of fuel. 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, and

•

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

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

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

Regulated Electric Business

Under the Restructuring Order, effective July 1, 2000, BGE's residential rates are frozen for a six-year period, and its commercial and industrial rates are frozen for four to six years. BGE entered into standard offer service arrangements with Constellation Power Source and Allegheny Energy Supply Company to provide the energy and capacity required to meet its standard offer service obligations through June 30, 2006.

Regulated Gas Business

We use basis swaps in the winter months (November through March) to hedge our price risk associated with natural gas purchases under our market-based rates incentive mechanism. We also use fixed-to-floating and floating-to-fixed swaps to hedge our price risk associated with our off-system gas sales.

        The fixed portion represents a specific dollar amount that we will pay or receive, and the floating portion represents a fluctuating amount based on a published index that we will receive or pay. Our regulated gas business internal guidelines do not permit the use of swap agreements for any purpose other than to hedge price risk.

        BGE's off-system gas sales activities represent trading activities under EITF 98-10. Accordingly, we use mark-to-market accounting to record these transactions. The trading activities relating to our off-system gas sales were not material at December 31, 2001 and 2000.

        We defer, as unrealized gains or losses, the changes in fair value of the swap agreements under the market-based rates incentive mechanism and the customers' portion of off-system gas sales in our Consolidated Balance Sheets. When amounts are paid under the agreements, we report the payments as gas costs in our Consolidated Statements of Income. We report the changes in fair value for the shareholders' portion of off-system gas sales in earnings as a component of gas costs.

Credit Risk

Credit risk is the loss that may result from counterparty non-performance. We are exposed to credit risk, primarily through Constellation Power Source. Constellation Power Source uses credit policies to manage its credit risk, including utilizing an established credit approval process, monitoring counterparty limits, employing credit mitigation measures such as margin, collateral or prepayment arrangements, and using master netting agreements. Constellation Power Source measures credit risk as the replacement cost for open energy commodity and derivative positions plus amounts owed from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where we have a legally enforceable right of setoff.

        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

65

counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, fail to deliver the electricity the power marketing operation had contracted for), we could sustain a loss that could have a material impact on our financial results.

        Electric and gas utilities, cooperatives, and energy marketers comprise the majority of counterparties underlying our assets from power marketing and risk management activities. We held cash collateral from counterparties totaling $3.5 million as of December 31, 2001 and $103.3 million as of December 31, 2000. These amounts are included in "Other deferred credits and other liabilities" in our Consolidated Balance Sheets.

Taxes

We summarize our income taxes in our Consolidated Statements of Income Taxes. As you read this section, it may be helpful to refer to those statements.

Income Tax Expense

We have two categories of income taxes in our Consolidated Statements of Income Taxes—current and deferred. We describe each of these below:

•

current income tax expense consists solely of regular tax less applicable tax credits, and

•

deferred income tax expense is equal to the changes in the net deferred income tax liability, excluding amounts charged or credited to accumulated other comprehensive income. Our deferred income tax expense is increased or reduced for changes to the "Income taxes recoverable through future rates (net)" regulatory asset (described later in this note) during the year.

Investment Tax Credits

We have deferred the investment tax credit associated with our regulated utility business and assets previously held by our regulated utility business in our Consolidated Balance Sheets. The investment tax credit is amortized evenly to income over the life of each property. We reduce income tax expense in our Consolidated Statements of Income for the investment tax credit and other tax credits associated with our nonregulated businesses, other than leveraged leases.

Deferred Income Tax Assets and Liabilities

We must report some of our revenues and expenses differently for our financial statements than for income tax return purposes. The tax effects of the differences in these items are reported as deferred income tax assets or liabilities in our Consolidated Balance Sheets. We measure the deferred income tax assets and liabilities using income tax rates that are currently in effect.

        A portion of our total deferred income tax liability relates to our regulated utility business, but has not been reflected in the rates we charge our customers. We refer to this portion of the liability as "Income taxes recoverable through future rates (net)." We have recorded that portion of the net liability as a regulatory asset in our Consolidated Balance Sheets. We discuss this further in Note 6.

State and Local Taxes

As discussed in Note 5, tax legislation has made comprehensive changes to the state and local taxation of electric and gas utilities. State and local income taxes are included in "Income taxes" in our Consolidated Statements of Income.

        Through December 31, 1999, we paid Maryland public service company franchise tax on our utility revenue from sales in Maryland instead of state income tax. We include the franchise tax in "Taxes other than income taxes" in our Consolidated Statements of Income.

Cash and Cash Equivalents

All highly liquid investments with original maturities of three months or less are considered cash equivalents.

        At December 31, 2000, $112.5 million of the cash balance included in our Consolidated Balance Sheets was restricted under certain collateral arrangements for our power marketing operation.

Inventory

We record our fuel stocks and materials and supplies at the lower of cost or market. We determine cost using the average cost method.

Real Estate Projects and Investments

In Note 4, we summarize the real estate projects and investments that are in our Consolidated Balance Sheets. The projects and investments primarily consist of:

•

approximately 1,600 acres of land holdings in various stages of development located at 11 sites in the central Maryland region,

•

a 4,500 unit mixed-use planned unit development located in Anne Arundel County, Maryland of which 1,300 residential units and 11 acres for commercial development remain,

•

an operating waste water treatment plant located in Anne Arundel County, Maryland, and

•

an equity interest in Corporate Office Properties Trust, a real estate investment trust.

        The costs incurred to acquire and develop properties are included as part of the cost of the properties.

Financial Investments and Trading Securities

In Note 4, we summarize the financial investments that are in our Consolidated Balance Sheets.

        SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, applies particular requirements to some of our investments in debt and equity securities. We report those investments at fair value, and we use either specific identification or average cost to determine their cost for computing realized gains or losses. We classify these investments as either trading securities or available-for-sale securities, which we describe separately on the next page. We report investments that are not covered by SFAS No. 115 at their cost.

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Trading Securities

Our other nonregulated businesses classify some of their investments in marketable equity securities and financial limited partnerships as trading securities. We include any unrealized gains or losses on these securities in "Nonregulated revenues" in our Consolidated Statements of Income.

Available-for-Sale Securities

We classify our investments in the nuclear decommissioning trust funds as available-for-sale securities. We describe the nuclear decommissioning trusts and the reserves under the heading "Nuclear Decommissioning" later in this note.

        In addition, our other nonregulated businesses classify some of their investments in marketable equity securities as available-for-sale securities, including the investment in Orion Power Holdings, Inc. (Orion) effective June 1, 2001. We discuss the accounting for the investment in Orion in more detail in Note 4.

        We include any unrealized gains or losses on our available-for-sale securities in "Accumulated other comprehensive income" in our Consolidated Statements of Common Shareholders' Equity and Consolidated Statements of Capitalization.

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

SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, requires us to evaluate certain assets that have long lives (generating property and equipment and real estate) to determine if they are impaired if certain conditions exist. We determine if long-lived assets are impaired by comparing their undiscounted expected future cash flows to their carrying amount in our accounting records. We would record an impairment loss if the undiscounted expected future cash flows from an asset were less than the carrying amount of the asset. Additionally, we evaluate our equity-method investments to determine whether they have experienced a loss in value that is considered other than a temporary decline in value.

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

Property, Plant and Equipment, Depreciation, Amortization, and Decommissioning

We report our property, plant and equipment at its original cost, unless impaired under the provisions of SFAS No. 121.

        Our original costs include:

•

material and labor,

•

contractor costs, and

•

construction overhead costs and financing costs (where applicable).

        We own an undivided interest in the Keystone and Conemaugh electric generating plants in Western Pennsylvania, as well as in the transmission line that transports the plants' output to the joint owners' service territories. Our ownership interests in these plants are 20.99% in Keystone and 10.56% in Conemaugh. These ownership interests represented a net investment of $150 million at December 31, 2001 and $143 million at December 31, 2000.

        The "Nonregulated generation property, plant and equipment" in our Consolidated Balance Sheets includes nonregulated generation construction work in progress of $1,158.6 million at December 31, 2001 and $908.7 million at December 31, 2000.

        When we retire or dispose of property, plant and equipment, we remove the asset's cost from our Consolidated Balance Sheets. We charge this cost to accumulated depreciation for assets that were depreciated under the composite, straight-line method. This includes regulated utility property, plant and equipment and nonregulated generating assets previously owned by the regulated utility. For all other assets, we remove the accumulated depreciation and amortization amounts from our Consolidated Balance Sheets and record any gain or loss in our Consolidated Statements of Income.

        The costs of maintenance and certain replacements are charged to "Operating expenses" in our Consolidated Statements of Income as incurred.

Depreciation Expense

We compute depreciation for our generating, electric transmission and distribution, and gas facilities over the estimated useful lives of depreciable property using either the:

•

composite, straight-line rates (approved by the Maryland PSC for our regulated utility business) applied to the average investment in classes of depreciable property based on an average rate of approximately three percent per year, or

•

units of production method.

        Other assets are depreciated using the straight-line method and the following estimated useful lives:

Asset	Estimated Useful Lives
Building and improvements	20 - 50 years
Transportation equipment	5 - 15 years
Office equipment and computer software	3 - 20 years

Amortization Expense

Amortization is an accounting process of reducing an amount in our Consolidated Balance Sheets evenly over a period of time that approximates the useful life of the related item. When we reduce amounts in our Consolidated Balance Sheets, we increase amortization expense in our Consolidated Statements of Income. An amount is considered fully amortized when it has been reduced to zero.

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Nuclear Fuel

We amortize nuclear fuel based on the energy produced over the life of the fuel including the quarterly fees we pay to the Department of Energy for the future disposal of spent nuclear fuel. These fees are based on the kilowatt-hours of electricity sold. We report the amortization expense for nuclear fuel in "Operating expenses" in our Consolidated Statements of Income.

Nuclear Decommissioning

We record an expense and a reserve for the costs expected to be incurred in the future to decommission the radioactive portion of Calvert Cliffs based on a sinking fund methodology. The accumulated decommissioning reserve is recorded in "Accumulated depreciation" in our Consolidated Balance Sheets. The total reserve was $304.6 million at December 31, 2001 and $275.4 million at December 31, 2000. Our contributions to the nuclear decommissioning trust funds were $22.0 million for 2001, $13.2 million for 2000, and $17.6 million for 1999.

        Under the Maryland PSC's order deregulating electric generation, BGE's customers must pay a total of $520 million in 1993 dollars, adjusted for inflation, to decommission Calvert Cliffs. BGE is collecting this amount on behalf of and passing it to Calvert Cliffs Nuclear Power Plant, Inc. Calvert Cliffs Nuclear Power Plant, Inc. is responsible for any difference between this amount and the actual costs to decommission the plant.

        We recorded a reserve for the costs expected to be incurred in the future to decommission the radioactive portion of Nine Mile Point under the discounted future cash flows methodology. The total reserve was $224.4 million at December 31, 2001. We have determined that the decommissioning trust funds established for Nine Mile Point are adequately funded to cover the future costs to decommission the radioactive portions of the plant and as such, no contributions were made to the trust funds during the year ended December 31, 2001.

        In accordance with Nuclear Regulatory Commission (NRC) regulations, we maintain external decommissioning trusts to fund the costs expected to be incurred to decommission Calvert Cliffs and Nine Mile Point. The assets in the trusts are reported in "Nuclear decommissioning trust funds" in our Consolidated Balance Sheets. The NRC requires utilities to provide financial assurance that they will accumulate sufficient funds to pay for the cost of nuclear decommissioning based upon either a generic NRC formula or a facility-specific decommissioning cost estimate. We use the facility-specific cost estimate for funding these costs and providing the required financial assurance.

        We classify the investments in the nuclear decommissioning trust funds as available-for-sale securities, and we report these investments at fair value in our Consolidated Balance Sheets as previously discussed in this note.

        As owners of Calvert Cliffs Nuclear Power Plant, we are required, along with other domestic utilities, by the Energy Policy Act of 1992 to make contributions to a fund for decommissioning and decontaminating the Department of Energy's uranium enrichment facilities. The contributions are generally payable over 15 years with escalation for inflation and are based upon the proportionate amount of uranium enriched by the Department of Energy for each utility. We amortize the deferred costs of decommissioning and decontaminating the Department of Energy's uranium enrichment facilities. The previous owners retained the obligation for Nine Mile Point.

Capitalized Interest and Allowance for Funds Used During Construction

Capitalized Interest

With the issuance of the Restructuring Order, we ceased accruing AFC (discussed below) for electric generation-related construction projects.

        Our nonregulated businesses capitalize interest costs under SFAS No. 34, Capitalizing Interest Costs, for costs incurred to finance our power plant construction projects and real estate developed for internal use.

Allowance for Funds Used During Construction (AFC)

We finance regulated utility construction projects with borrowed funds and equity funds. We are allowed by the Maryland PSC to record the costs of these funds as part of the cost of construction projects in our Consolidated Balance Sheets. We do this through the AFC, which we calculate using a rate authorized by the Maryland PSC. We bill our customers for the AFC plus a return after the utility property is placed in service.

        The AFC rates are 9.4% for electric plant, 8.6% for gas plant, and 9.2% for common plant. We compound AFC annually.

Long-Term Debt

We defer all costs related to the issuance of long-term debt. These costs include underwriters' commissions, discounts or premiums, other costs such as legal, accounting, and regulatory fees, and printing costs. We amortize these costs to expense over the life of the debt.

        When we incur gains or losses on debt that we retire prior to maturity in our regulated utility business, we amortize those gains or losses over the remaining original life of the debt.

Use of Accounting Estimates

Management makes estimates and assumptions when preparing financial statements under accounting principles generally accepted in the United States of America. These estimates and assumptions affect various matters, including:

•

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

•

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

•

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

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

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Reclassifications

We have reclassified certain prior-year amounts for comparative purposes. These reclassifications did not affect consolidated net income for the years presented.

Accounting Standards Adopted

On January 1, 2001, we adopted SFAS No. 133, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities.

        These statements require that we recognize all derivatives on the balance sheet at fair value. Changes in the value of derivatives that are not hedges must be recorded in earnings.

        We use derivatives in connection with our power marketing and risk management activities and to hedge the risk of variations in future cash flows from forecasted purchases and sales of electricity and gas in our electric generation operations as more fully described in the Risk Management section. Under SFAS No. 133, changes in the value of derivatives designated as hedges that are effective in offsetting the variability in cash flows of forecasted transactions are recognized in other comprehensive income until the forecasted transactions occur. The ineffective portion of changes in fair value of derivatives used as cash-flow hedges is immediately recognized in earnings.

        In accordance with the transition provisions of SFAS No. 133, we recorded the following at January 1, 2001:

•

an $8.5 million after-tax cumulative effect adjustment that increased earnings, and

•

a $35.5 million after-tax cumulative effect adjustment that reduced other comprehensive income.

        The cumulative effect adjustment recorded in earnings represents the fair value as of January 1, 2001 of a warrant for 705,900 shares of common stock of Orion. The warrant had an exercise price of $10 per share and was received in conjunction with our investment in Orion. As part of the sale of Orion to Reliant Resources, Inc., we received cash equal to the difference between Reliant's purchase price of $26.80 per share and the exercise price multiplied by the number of shares subject to the warrant.

        The cumulative effect adjustment recorded in other comprehensive income represents certain forward sales of electricity that we designated as cash-flow hedges of forecasted transactions primarily through our merchant energy business.

Recently Issued Accounting Standards

In 2001, the FASB issued SFAS No. 141, Business Combinations, SFAS No. 142, Goodwill and Other Intangible Assets, SFAS No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets, and SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.

        SFAS No. 141 requires all business combinations to be accounted for under the purchase method. Use of the pooling-of-interests method is prohibited for business combinations initiated after June 30, 2001. This statement also establishes criteria for the separate recognition of intangible assets acquired in a business combination. We do not expect the adoption of this statement to have a material impact on our financial results.

        SFAS No. 142 requires that goodwill no longer be amortized to earnings, but instead be subject to periodic testing for impairment. This statement is effective for fiscal years beginning after December 15, 2001, with earlier application permitted only in specified circumstances. We do not expect the adoption of this statement to have a material impact on our financial results.

        SFAS No. 143 provides the accounting requirements for asset retirement obligations associated with tangible long-lived assets. This statement is effective for fiscal years beginning after June 15, 2002, and early adoption is permitted. Currently, we are evaluating this statement and have not determined its impact on our financial results, however, it could be material.

        SFAS No. 144 replaces FASB Statement No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. SFAS No. 144 addresses financial reporting for the impairment or disposal of long-lived assets. This statement is effective for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years, with early application encouraged. We do not expect the adoption of this statement to have a material impact on our financial results. However, we expect to reclassify our senior-living facilities business as a discontinued operation in the first quarter of 2002 as required under this standard.

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2 Contract Termination, Workforce Reduction, and Other Special Costs

2001 Events
		Pre-Tax		After-Tax
		(In millions)
Workforce reduction costs:
	Voluntary termination benefits—VSERP	$	70.1	$	42.5
	Settlement and curtailment charges		16.3		9.9
	Involuntary severance accrual		19.3		11.7
	Total workforce reduction costs		105.7		64.1
Contract termination related costs			224.8		139.6
Impairment losses and other costs:
	Loss on sale of Guatemalan operation		43.3		28.1
	Impairments of real estate, senior-living and international investments		107.3		69.7
	Cancellation of domestic power projects		46.9		30.5
	Reduction of financial investment		4.6		2.8
	Total impairment losses and other costs		202.1		131.1
Total special costs		$	532.6	$	334.8

Workforce Reduction Costs

Voluntary Special Early Retirement Programs—VSERP

In the fourth quarter of 2001, we undertook several measures to reduce our workforce through both voluntary and involuntary means. The purpose of these programs was to reduce our operating costs to become more competitive. We offered several Voluntary Special Early Retirement Programs (VSERP) to employees of Constellation Energy and certain subsidiaries. The first group of these programs offered enhanced early retirement benefits to employees age 55 or older with 10 or more years of service. The second group of these programs offered enhanced early retirement benefits to employees age 50 to 54 with 20 or more years of service.

        Since employees electing to participate in the age 55 or older VSERP had to make their elections by the end of 2001, the cost of that program was reflected in 2001. The $70.1 million in the above table reflects the portion of the total cost of that program charged to expense for the 507 employees that elected to participate. BGE recorded $37.9 million of this amount. BGE also recorded $13.7 million on its balance sheet as a regulatory asset related to its gas business as discussed in Note 6.

Settlement and Curtailment Charges

In connection with the age 55 or older VSERP, a significant number of the participants in our nonqualified pension plans are retiring. As a result, we recognized a settlement loss of approximately $10.5 million and a curtailment loss of approximately $5.8 million for those plans in accordance with SFAS No. 88, Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits. BGE recorded $6.6 million of this amount. Additional details on the VSERP and their impact on our pension and postretirement benefit plans are discussed in Note 7.

Involuntary Severance Accrual

The voluntary programs were designed, offered, and timed to minimize the number of employees who will be involuntarily severed under our overall workforce reduction plan. Our workforce reduction plan identified 435 jobs to be eliminated over and above position reductions expected to be satisfied through the age 55 and over VSERP and was specific as to company, organizational unit, and position. However, the number of employees that will elect to voluntarily retire under the age 50 to 54 VSERP and how many will thereafter be involuntarily severed is unknown until after the election period of the VSERP ends in February 2002.

        In accordance with EITF 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring), the Company recognized a liability of $25.1 million at December 31, 2001 for the targeted number of involuntary terminations that will result if no employees elect the age 50 to 54 VSERP. The $19.3 million in the table above represents involuntary severance charged to expense in 2001 in connection with our workforce reduction programs. BGE recorded $12.5 million of this amount. BGE also recorded $5.8 million on its balance sheet as a regulatory asset related to its gas business as discussed in Note 6. We will record any additional cost in excess of the 2001 involuntary severance accrual for those eligible participants that elect the 50 to 54 VSERP in 2002.

Contract Termination Related Costs

On October 26, 2001, we announced the decision to remain a single company and canceled prior plans to separate our merchant energy business from our remaining businesses.

        We also announced the termination of our power business services agreement with Goldman Sachs. We paid Goldman Sachs a total of $355 million, representing $196.7 million to terminate the power business services agreement with our power marketing operation and $159 million previously recognized as a payable for services rendered under the agreement. Goldman Sachs also will not make an equity investment in our merchant energy business as previously announced.

        In addition, we terminated a software agreement we had whereby Goldman Sachs would provide maintenance, support, and minor upgrades to our risk management and trading system. We recognized $17.6 million in expense in the fourth quarter of 2001 representing the unamortized prepaid costs related to this agreement. Finally, we incurred approximately $10.5 million in employee-related expenses and advisory costs from investment bankers and legal counsel. In total, we recognized expenses of approximately $224.8 million in the fourth quarter of 2001

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relating to the termination of our relationship with Goldman Sachs and our decision not to separate.

Impairment Losses and Other Costs

Sale of Guatemalan Operation

On November 8, 2001, we sold our Guatemalan power plant operations to an affiliate of Duke Energy International, LLC, the international business unit of Duke Energy. Through this sale, Duke Energy acquired Grupo Generador de Guatemala y Cia., S.C.A., which owns two generating plants at Esquintla and Lake Amatitlan in Guatemala. The combined capacity of the plants is 167 megawatts. We decided to sell our Guatemalan operations to focus our efforts on our core energy businesses. As a result of this transaction, we are no longer committed to making significant future capital investments in a non-core operation. We recorded a $43.3 million loss on this sale.

Impairments of Real Estate, Senior-Living, and Other International Investments

In the fourth quarter of 2001, our other nonregulated businesses recorded $107.3 million in impairments of certain real estate projects, senior-living facilities, and international assets to reflect the fair value of these investments. These investments represent non-core assets with a book value of approximately $140.6 million after these impairments. As part of our focus on capital and cash requirements and on our core energy businesses, the following occurred:

•

We decided to sell six real estate projects without further development and all of our 18 senior-living facilities in 2002 and accelerate the exit strategies for two other real estate projects that we will continue to hold and own over the next several years. The real estate projects include approximately 1,300 acres of land holdings in various stages of development located in seven sites in the central Maryland region and an operating waste water treatment plant located in Anne Arundel County, Maryland.

•

We decided to accelerate the exit strategy for our interest in a Panamanian electric distribution company. As a non-core asset, management has decided to reduce the cost and risk of holding this asset indefinitely and intends to dispose of this asset. We believe a sale of this investment can be completed by mid-to-late 2003.

•

We incurred an other than temporary decline in our equity method investment in the Bolivian Generating Group, which owns an interest in an electric generation concession in Bolivia. This decline in value resulted from a deterioration of our investment's position in the dispatch curve of its capacity market. As a result, we recorded the impairment in accordance with the provisions of Accounting Principles Board Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock.

        The impairments of our real estate, senior-living facilities, and Panama investments were recorded in accordance with the provisions of SFAS No. 121. These impairments resulted from our change from an intent to hold to an intent to sell certain of these non-core assets in 2002, and our decision to limit future costs and risks by accelerating the exit strategies for certain assets that cannot be sold by the end of 2002. Previously, our strategy for these investments was to hold them until we could obtain reasonable value. Under that strategy, the expected cash flows were greater than our investment and no impairment was recognized.

Impairment of Domestic Power Projects

In the fourth quarter of 2001, our merchant energy business recorded impairments of $46.9 million primarily due to $40.8 million in impairments under SFAS No. 121 associated with the termination of our planned development projects in Texas, California, Florida, and Massachusetts that are not currently under construction. The impairments include amounts paid for the purchase of four turbines related to these development projects. We decided to terminate our development projects due to the expected excess generation capacity in most domestic markets and the significant decline in the forward market prices of electricity. In accordance with the provisions of APB No. 18, we recognized $6.1 million for an other than temporary decline in the value of our investment in a waste burning power plant in Michigan where operating cash flows are not sufficient to pay existing debt service and we are not likely to recover our equity interest in this investment.

Reduction of Financial Investment

Our financial investments business recorded a $4.6 million reduction of its investment in a leased aircraft due to the other than temporary decline in the estimated residual value of used airplanes as a result of the September 11, 2001 terrorist attacks and the general downturn in the aviation industry. This investment is accounted for as a leveraged lease under SFAS No. 13, Accounting for Leases.

2000 Events

In 2000, BGE offered a targeted VSERP to employees ages 55 or older with 10 or more years of service in targeted positions that elected to retire on June 1, 2000 to reduce our operating costs to become more competitive. BGE recorded approximately $10.0 million pre-tax for employees that elected to participate in the program. Of this amount, BGE recorded approximately $3.0 million on its balance sheet as a regulatory asset of its gas business. BGE is amortizing this regulatory asset over a 5-year period as provided by the June 2000 Maryland PSC gas base rate order as discussed in Note 6. The remaining $7.0 million, or $4.2 million after-tax, related to BGE's electric business and was charged to expense.

1999 Events

Our generation operation recorded a $21.4 million pre-tax, or $14.2 million after-tax, impairment of two geothermal power projects. These impairments occurred because the expected future cash flows from the projects are less than the investment in the projects. For the first project, this resulted from the

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inability to restructure certain project agreements. For the second project, we experienced a declining water temperature of the geothermal resource used by one of the plants for production.

        Our Latin American operation recorded a $7.1 million pre-tax, or $4.5 million after-tax, impairment to reflect the fair value of our investment in a generating company in Bolivia as a result of our international exit strategy at that time to focus on our core businesses.

        Our financial investments exchanged its shares of common stock in Capital Re, an insurance company, for common stock of ACE Limited (ACE) as part of a business combination whereby ACE acquired all of the outstanding capital stock of Capital Re. As a result, our financial investments operation wrote-down its $94.2 million investment in Capital Re stock by $26.2 million pre-tax, or $16.0 million after-tax, to reflect the closing price of the business combination.

        Our real estate and senior-living facilities operations entered into an agreement to sell all but one of its senior-living facilities to Sunrise Assisted Living, Inc. Under the terms of the agreement, Sunrise was to acquire twelve of our existing senior-living facilities, three facilities under construction, and several sites under development for $72.2 million in cash and $16.0 million in debt assumption. We could not reach an agreement on financing issues that subsequently arose, and the agreement was terminated in November 1999. However, our real estate and senior-living operations recorded a $9.6 million pre-tax, or $5.8 million after-tax, impairment related to the proposed sale of these facilities.

3 Information by Operating Segment

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

•

Our nonregulated merchant energy business in North America:

–

provides power marketing, origination transactions, and risk management services,

–

develops, owns, and operates generating facilities and/or power projects in North America, and

–

provides nuclear consulting services.

•

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

•

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

        We have restated certain prior-period information for comparative purposes based on our reportable operating segments.

        Effective July 1, 2000, the financial results of the electric generation portion of our business are included in the merchant energy business segment. Prior to that date, the financial results of electric generation are included in our regulated electric business.

        Our remaining nonregulated businesses:

•

provide energy products and services,

•

sell and service electric and gas appliances, and heating and air conditioning systems, engage in home improvements, and sell electricity and natural gas through mass marketing efforts,

•

provide cooling services,

•

engage in financial investments,

•

develop, own, and manage real estate and senior-living facilities, and

•

own interests in Latin American power generation and distribution projects and investments.

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

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	Merchant Energy Business		Regulated Electric Business		Regulated Gas Business		Other Nonregulated Businesses			Unallocated Corporate Items and Eliminations			Consolidated
	(In millions)
2001
Unaffiliated revenues	$	614.3	$	2,039.6	$	674.3	$	600.1		$	—		$	3,928.3
Intersegment revenues		1,151.2		0.4		6.4		2.0			(1,160.0	)		—
Total revenues		1,765.5		2,040.0		680.7		602.1			(1,160.0	)		3,928.3
Depreciation and amortization		174.9		173.3		47.7		23.2			—			419.1
Fixed charges		25.8		135.8		28.5		48.7			—			238.8
Income tax expense (benefit)		25.2		36.8		25.7		(49.8	)		—			37.9
Cumulative effect of change in accounting principle		—		—		—		8.5			—			8.5
Net income (loss) (a)		93.1		50.9		37.5		(90.6	)		—			90.9
Segment assets		8,134.3		3,764.9		1,104.2		1,314.0			(239.8	)		14,077.6
Capital expenditures		1,815.0		180.3		58.7		35.0			—			2,089.0
2000
Unaffiliated revenues	$	421.1	$	2,134.7	$	603.8	$	692.9		$	—		$	3,852.5
Intersegment revenues		604.6		0.5		7.8		20.4			(633.3	)		—
Total revenues		1,025.7		2,135.2		611.6		713.3			(633.3	)		3,852.5
Depreciation and amortization		83.6		319.9		46.2		20.3			—			470.0
Equity in income of equity-method investees (b)		—		2.4		—		—			—			2.4
Fixed charges		18.3		168.4		27.3		65.8			(8.4	)		271.4
Income tax expense		118.5		72.2		21.9		17.5			—			230.1
Net income (c)		198.6		102.3		30.6		13.8			—			345.3
Segment assets		7,295.5		3,392.3		1,089.9		1,491.5			(329.9	)		12,939.3
Capital expenditures		699.0		290.3		59.7		131.5			—			1,180.5
1999
Unaffiliated revenues	$	277.3	$	2,258.8	$	476.5	$	828.3		$	—		$	3,840.9
Intersegment revenues		—		1.2		11.6		20.1			(32.9	)		—
Total revenues		277.3		2,260.0		488.1		848.4			(32.9	)		3,840.9
Depreciation and amortization		7.5		376.4		44.9		21.0			—			449.8
Equity in income of equity-method investees (b)		—		5.1		—		—			—			5.1
Fixed charges		—		174.2		26.1		56.1			(1.4	)		255.0
Income tax expense (benefit)		29.2		149.2		18.1		(10.1	)		—			186.4
Extraordinary loss		—		66.3		—		—			—			66.3
Net income (loss) (d)		52.4		198.8		33.0		(24.1	)		—			260.1
Segment assets		1,259.0		6,312.6		915.3		1,239.7			18.5			9,745.1
Capital expenditures		163.0		366.8		69.2		115.2			—			714.2

(a) Our merchant energy business, our regulated electric business, our regulated gas business, and our other nonregulated businesses recognized $198.1 million, $33.6 million, $0.8 million, and $102.3 million, respectively, for workforce reduction costs, contract termination related costs, and impairment losses and other costs as described more fully in Note 2.

(b) Our merchant energy business records its equity in the income of equity method investees in unaffiliated revenues.

(c) Our regulated electric business recorded expense of $4.2 million related to employees that elected to participate in a Voluntary Special Early Retirement Program. In addition, our merchant energy business recorded a $15.0 million deregulation transition cost incurred by our power marketing operation.

(d) Our regulated electric business recorded expense of $4.9 million related to Hurricane Floyd. Our merchant energy business recorded $14.2 million for the impairment of two geothermal power plants. Our Latin American operation recorded $4.5 million for the impairment to reflect the fair value of our investment in a power project in Bolivia. Our financial investments operation recorded $16.0 million for the reduction of its investment in Capital Re stock to reflect the market value of this investment. Our real estate and senior-living facilities operation recorded $5.8 million for the impairment of certain senior-living facilities.

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4 Investments

Real Estate Projects and Investments

Real estate projects and investments held by Constellation Real Estate Group (CREG), consist of the following:

At December 31,	2001		2000
	(In millions)
Properties under development	$	100.5	$	165.1
Operating properties (net of accumulated depreciation)		0.9		12.7
Equity interest in real estate investments		109.3		112.5
Total real estate projects and investments	$	210.7	$	290.3

        See Note 2 for a discussion of impairments recorded in 2001.

Power Projects

Investments in power projects held by our merchant energy business consist of the following:

At December 31,	2001		2000
	(In millions)
Equity Method	$	480.3	$	488.4
Cost Method		10.7		10.8
Total power projects	$	491.0	$	499.2

        Our percentage voting interest in power projects accounted for under the equity method ranges from 16% to 50%. Equity in earnings of these power projects were $24.2 million in 2001, $50.2 million in 2000, and $49.7 million in 1999.

        Our power projects accounted for under the equity method include investments of $296.4 million in 2001 and $297.9 million in 2000 that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. We discuss these projects further in Note 11.

        Our Latin American operation held power projects of $8.1 million at December 31, 2001 and $11.4 million at December 31, 2000.

        See Note 2 for a discussion of impairments recorded in 2001.

Orion and Financial Investments

Financial investments consist of the following:

At December 31,	2001		2000
	(In millions)
Orion	$	442.5	$	192.0
Marketable equity securities		20.2		105.9
Financial limited partnerships		25.8		32.7
Leveraged leases		14.7		22.4
Total financial investments	$	503.2	$	353.0

Investments Classified as Available-for-Sale

We classify the following investments as available-for-sale:

•

nuclear decommissioning trust funds,

•

our other nonregulated businesses' marketable equity securities (shown above), and

•

Orion.

        This means we do not expect to hold them to maturity, and we do not consider them trading securities.

        Effective June 1, 2001, we changed our accounting for the investment in Orion from the equity method to the cost method. This change resulted from no longer having significant influence as required under equity method accounting due to a reduction in our ownership percentage. Our ownership percentage decreased due to Orion's issuance of 13 million shares of common stock that were sold in a public offering and due to our sale of one million shares as part of the offering. At December 31, 2001, the unrealized gain on our investment in Orion was $244.0 million. In addition, at December 31, 2001, we owned a warrant for 705,900 shares of common stock in Orion with a fair market value of $11.8 million. These warrants are accounted for under SFAS No. 133 as discussed in Note 1.

        We show the fair values, gross unrealized gains and losses, and amortized cost bases for all of our available-for-sale securities, in the following tables. We use specific identification to determine cost in computing realized gains and losses, except we use average cost basis for our investment in Orion.

At December 31, 2001	Amortized Cost Basis		Unrealized Gains		Unrealized Losses			Fair Value
	(In millions)
Marketable equity securities	$	773.9	$	270.6	$	(10.3	)	$	1,034.2
Corporate debt and U.S. Government agency		47.7		1.5		—			49.2
State municipal bonds		38.4		3.3		(0.2	)		41.5
Totals	$	860.0	$	275.4	$	(10.5	)	$	1,124.9

At December 31, 2000	Amortized Cost Basis		Unrealized Gains		Unrealized Losses			Fair Value
	(In millions)
Marketable equity securities	$	171.8	$	68.9	$	(2.2	)	$	238.5
Corporate debt and U.S. Government agency		26.1		0.1		(0.1	)		26.1
State municipal bonds		61.3		2.3		(0.4	)		63.2
Totals	$	259.2	$	71.3	$	(2.7	)	$	327.8

        In addition to the above securities, the nuclear decommissioning trust funds included $7.7 million at December 31, 2001 and $6.8 million at December 31, 2000 of cash and cash equivalents.

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        The preceding tables include $21.0 million in 2001 and $34.7 million in 2000 of unrealized net gains associated with the nuclear decommissioning trust funds that are reflected as a change in the nuclear decommissioning trust funds in our Consolidated Balance Sheets.

        Gross and net realized gains and losses on available-for-sale securities were as follows:

	2001			2000			1999
	(In millions)
Gross realized gains	$	47.6		$	54.5		$	11.7
Gross realized losses		(7.9	)		(8.0	)		(38.8	)
Net realized gains (losses)	$	39.7		$	46.5		$	(27.1	)

        The corporate debt securities, U.S. Government agency obligations, and state municipal bonds mature on the following schedule:

At December 31, 2001	Amount
	(In millions)
Less than 1 year	$	8.4
1-5 years		34.3
5-10 years		22.2
More than 10 years		25.8
Total maturities of debt securities	$	90.7

5 Rate Matters and Accounting Impacts of Deregulation

On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition Act of 1999 (the "Act") and accompanying tax legislation that significantly restructured Maryland's electric utility industry and modified the industry's tax structure. In the Restructuring Order discussed below, the Maryland PSC addressed the major provisions of the Act.

        The tax legislation made comprehensive changes to the state and local taxation of electric and gas utilities. Effective January 1, 2000, the Maryland public service franchise tax was altered to generally include a tax equal to .062 cents on each kilowatt-hour of electricity and .402 cents on each therm of natural gas delivered for final consumption in Maryland. The Maryland 2% franchise tax on electric and natural gas utilities continues to apply to transmission and distribution revenue. Additionally, all electric and natural gas utility results are subject to the Maryland corporate income tax.

        Beginning July 1, 2000, the tax legislation also provided for a two-year phase-in of a 50% reduction in the local personal property taxes on machinery and equipment used to generate electricity for resale and a 60% corporate income tax credit for real property taxes paid on those facilities.

        On November 10, 1999, the Maryland PSC issued a Restructuring Order that resolved the major issues surrounding electric restructuring, accelerated the timetable for customer choice, and addressed the major provisions of the Act. The Restructuring Order also resolved the electric restructuring proceeding (transition costs, customer price protections, and unbundled rates for electric services) and a petition filed in September 1998 by the Office of People's Counsel (OPC) to lower our electric base rates. The major provisions of the Restructuring Order are:

•

All customers can choose their electric energy supplier beginning July 1, 2000. BGE will provide a standard offer service for customers that do not select an alternative supplier. In either case, BGE will continue to deliver electricity to all customers in areas traditionally served by BGE.

•

BGE reduced residential base rates by approximately 6.5%, on average about $54 million a year, beginning July 2000. These rates will not change before July 2006.

•

Commercial and industrial customers have up to four service options that will fix electric energy rates and transition charges for a period that ends in 2004 to 2006.

•

BGE's electric fuel rate clause was discontinued effective July 1, 2000.

•

Electric delivery service rates are frozen through June 2004 for commercial and industrial customers. The generation and transmission components of rates are frozen for different time periods depending on the service options selected by those customers.

•

BGE collects $528 million after-tax of its potentially stranded investments and utility restructuring costs through a competitive transition charge on its customers' bills. Residential customers will pay this charge through 2006. Commercial and industrial customers will pay in a lump sum or over a period ending in 2004 to 2006, depending on the service option selected by each customer.

•

Generation-related regulatory assets and nuclear decommissioning costs are included in delivery service rates effective July 1, 2000 and will be recovered on a basis approximating their amortization schedules prior to July 1, 2000.

•

Effective July 1, 2000, BGE unbundled rates to show separate components for delivery service, competitive transition charges, standard offer services (generation), transmission, universal service, and taxes.

•

Effective July 1, 2000, BGE transferred, at book value, its ten Maryland-based fossil and nuclear power plants

75

and its partial ownership interest in two coal plants and a hydroelectric plant in Pennsylvania to nonregulated subsidiaries of Constellation Energy.

•

BGE reduced its generation assets by $150 million pre-tax during the period July 1, 1999 - June 30, 2000 to mitigate a portion of BGE's potentially stranded investments.

•

Universal service is being provided for low-income customers without increasing their bills. BGE will provide its share of a statewide fund totaling $34 million annually.

        As discussed in Note 1, EITF 97-4 requires that a company should cease applying SFAS No. 71 when either legislation is passed or a regulatory body issues an order that contains sufficient detail to determine how the transition plan will affect the deregulated portion of the business. Additionally, a company would continue to recognize regulatory assets and liabilities in the Consolidated Balance Sheets to the extent that the transition plan provides for their recovery.

        We believe that the Restructuring Order provided sufficient details of the transition plan to competition for BGE's electric generation business to require BGE to discontinue the application of SFAS No. 71 for that portion of its business. Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101 and EITF 97-4 for BGE's electric generation business.

        SFAS No. 101 requires the elimination of the effects of rate regulation that have been recognized as regulatory assets and liabilities pursuant to SFAS No. 71. However, EITF 97-4 requires that regulatory assets and liabilities that will be recovered in the regulated portion of the business continue to be classified as regulatory assets and liabilities. The Restructuring Order provided for the creation of a single, new generation-related regulatory asset to be recovered through BGE's regulated transmission and distribution business. We discuss this further in Note 6.

        Pursuant to SFAS No. 101, the book value of property, plant and equipment may not be adjusted unless those assets are impaired under the provisions of SFAS No. 121. The process we used in evaluating and measuring impairment under the provisions of SFAS No. 121 involved two steps. First, we compared the net book value of each generating plant to the estimated undiscounted future net operating cash flows from that plant. An electric generating plant was considered impaired when its undiscounted future net operating cash flows were less than its net book value. Second, we computed the fair value of each plant that is determined to be impaired based on the present value of that plant's estimated future net operating cash flows discounted using an interest rate that considers the risk of operating that facility in a competitive environment. To the extent that the net book value of each impaired electric generation plant exceeded its fair value, we reduced its book value.

        Under the Restructuring Order, BGE will recover $528 million after-tax of its potentially stranded investments and utility restructuring costs through the competitive transition charge component of its customer rates beginning July 1, 2000. This recovery mostly relates to the stranded costs associated with the Calvert Cliffs Nuclear Power Plant, whose book value was substantially higher than its estimated fair value. However, Calvert Cliffs was not considered impaired under the provisions of SFAS No. 121 since its estimated future undiscounted cash flows exceeded its book value. Accordingly, BGE did not record any impairment related to Calvert Cliffs. However, BGE recognized after-tax impairment losses totaling $115.8 million associated with certain of its fossil plants under the provisions of SFAS No. 121.

        BGE had contracts to purchase electric capacity and energy that became uneconomic upon the deregulation of electric generation. Therefore, BGE recorded a $34.2 million after-tax charge based on the net present value of the excess of estimated contract costs over the market-based revenues to recover these costs over the remaining terms of the contracts. In addition, BGE had deferred certain energy conservation expenditures that would not be recovered through its transmission and distribution business under the Restructuring Order. Accordingly, BGE recorded a $10.3 million after-tax charge to eliminate the regulatory asset previously established for these deferred expenditures.

        At December 31, 1999, the total charge for BGE's electric generating plants that were impaired, losses on uneconomic purchased capacity and energy contracts, and deferred energy conservation expenditures was approximately $160.3 million after-tax.

        BGE recorded approximately $94.0 million of the $160.3 million on its balance sheet. This consisted of a $150.0 million regulatory asset of its regulated transmission and distribution business, net of approximately $56.0 million of associated deferred income taxes. The regulatory asset was amortized as it was recovered from ratepayers through June 30, 2000. This accomplished the $150 million reduction of its generation plants required by the Restructuring Order.

        BGE recorded an after-tax, extraordinary charge against earnings for approximately $66.3 million related to the remaining portion of the $160.3 million described above that was not recovered under the Restructuring Order.

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6 Regulatory Assets (net)

As discussed in Note 1, the Maryland PSC provides the final determination of the rates we charge our customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under accounting principles generally accepted in the United States of America. However, sometimes the Maryland PSC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers. When this happens, we must defer certain utility expenses and income in our Consolidated Balance Sheets as regulatory assets and liabilities. We then record them in our Consolidated Statements of Income (using amortization) when we include them in the rates we charge our customers.

        We summarize regulatory assets and liabilities in the following table, and we discuss each of them separately below.

At December 31,	2001		2000
	(In millions)
Electric generation-related regulatory asset	$	249.0	$	267.8
Income taxes recoverable through future rates (net)		95.6		101.2
Deferred postretirement and postemployment benefit costs		35.5		38.7
Deferred environmental costs		26.0		28.8
Deferred fuel costs (net)		33.5		71.1
Workforce reduction costs		21.6		2.8
Other (net)		2.6		4.5
Total regulatory assets (net)	$	463.8	$	514.9

Electric Generation-Related Regulatory Asset

With the issuance of the Restructuring Order, BGE no longer met the requirements for the application of SFAS No. 71 for the electric generation portion of its business. In accordance with SFAS No. 101 and EITF 97-4, all individual generation-related regulatory assets and liabilities must be eliminated from our balance sheet unless these regulatory assets and liabilities will be recovered in the regulated portion of the business. Pursuant to the Restructuring Order, BGE wrote-off all of its individual, generation-related regulatory assets and liabilities. BGE established a single, new generation-related regulatory asset for amounts to be collected through its regulated transmission and distribution business. The new regulatory asset is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules.

Income Taxes Recoverable Through Future Rates (net)

As described in Note 1, income taxes recoverable through future rates are the portion of our net deferred income tax liability that is applicable to our regulated utility business, but has not been reflected in the rates we charge our customers. These income taxes represent the tax effect of temporary differences in depreciation and the allowance for equity funds used during construction, offset by differences in deferred tax rates and deferred taxes on deferred investment tax credits. We amortize these amounts as the temporary differences reverse.

Deferred Postretirement and Postemployment Benefit Costs

Deferred postretirement and postemployment benefit costs are the costs we recorded under SFAS No. 106 (for postretirement benefits) and No. 112 (for postemployment benefits) in excess of the costs we included in the rates we charge our customers. We began amortizing these costs over a 15-year period in 1998. We discuss these costs further in Note 7.

Deferred Environmental Costs

Deferred environmental costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss this further in Note 11. We are amortizing $21.6 million of these costs (the amount we had incurred through October 1995) and $6.4 million of these costs (the amount we incurred from November 1995 through June 2000) over 10-year periods in accordance with the Maryland PSC's orders.

Deferred Fuel Costs

As described in Note 1, deferred fuel costs are the difference between our actual costs of electric fuel, net purchases and sales of electricity, and natural gas, and our fuel rate revenues collected from customers. We reduce deferred fuel costs as we collect them from or refund them to our customers.

        We show our deferred fuel costs in the following table.

At December 31,	2001		2000
	(In millions)
Electric	$	—	$	42.3
Gas		33.5		28.8
Deferred fuel costs (net)	$	33.5	$	71.1

        Under the terms of the Restructuring Order, BGE's electric fuel rate clause was discontinued effective July 1, 2000. In September 2000, the Maryland PSC approved the collection of the $54.6 million accumulated difference between our actual costs of fuel and energy and the amounts collected from customers that were deferred under the electric fuel rate clause through June 30, 2000. We collected this accumulated difference from customers over the twelve-month period ending October 2001.

Workforce Reduction Costs

The portions of the workforce reduction costs associated with the VSERP and involuntary severance programs we announced in 2001 and 2000 that relate to BGE's gas business are deferred as regulatory assets in accordance with the Maryland PSC's orders in prior rate cases. These costs are amortized over 5-year periods. See Note 2 and Note 7.

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7 Pension, Postretirement, Other Postemployment, and Employee Savings Plan Benefits

We offer pension, postretirement, other postemployment, and employee savings plan benefits. We describe each of these separately below. Nine Mile Point offers its own pension, postretirement, other postemployment, and employee savings plan benefits to its employees. The benefits for Nine Mile Point are included in the tables beginning on the next page.

Pension Benefits

We sponsor several defined benefit pension plans for our employees. These include the basic, qualified plan that most employees participate in and several nonqualified plans that are available only to certain employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. Employees do not contribute to these plans. Generally, we calculate the benefits under these plans based on age, years of service, and pay.

        Sometimes we amend the plans retroactively. These retroactive plan amendments require us to recalculate benefits related to participants' past service. We amortize the change in the benefit costs from these plan amendments on a straight-line basis over the average remaining service period of active employees.

        We fund the plans by contributing at least the minimum amount required under Internal Revenue Service regulations. We calculate the amount of funding using an actuarial method called the projected unit credit cost method. The assets in all of the plans at December 31, 2001 were mostly marketable equity and fixed income securities.

        In 1999, we made the following amendments:

•

eligible participants were allowed to choose between an enhanced version of the current benefit formula and a new pension equity plan (PEP) formula. Pension benefits for eligible employees hired after December 31, 1999 are based on a PEP formula, and

•

pension and survivor benefits were increased for participants who retired prior to January 1, 1994 and for their surviving spouses.

        The financial impacts of the amendments are included in the tables beginning on the next page.

Postretirement Benefits

We sponsor defined benefit postretirement health care and life insurance plans that cover substantially all of our employees. Generally, we calculate the benefits under these plans based on age, years of service, and pension benefit levels. We do not fund these plans.

        For nearly all of the health care plans, retirees make contributions to cover a portion of the plan costs.

        Contributions for employees who retire after June 30, 1992 are calculated based on age and years of service. The amount of retiree contributions increases based on expected increases in medical costs. For the life insurance plan, retirees do not make contributions to cover a portion of the plan costs.

        Effective January 1, 1993, we adopted SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. The adoption of that statement caused:

•

a transition obligation, which we are amortizing over 20 years, and

•

an increase in annual postretirement benefit costs.

        For our nonregulated businesses, we expense all postretirement benefit costs. For our regulated utility business, we accounted for the increase in annual postretirement benefit costs under two Maryland PSC rate orders:

•

in an April 1993 rate order, the Maryland PSC allowed us to expense one-half and defer, as a regulatory asset (see Note 6), the other half of the increase in annual postretirement benefit costs related to our regulated electric and gas businesses, and

•

in a November 1995 rate order, the Maryland PSC allowed us to expense all of the increase in annual postretirement benefit costs related to our regulated gas business.

        Beginning in 1998, the Maryland PSC authorized us to:

•

expense all of the increase in annual postretirement benefit costs related to our regulated electric business, and

•

amortize the regulatory asset for postretirement benefit costs related to our regulated electric and gas businesses over 15 years.

VSERP

In 2001, our Board of Directors approved several voluntary retirement programs for Constellation Energy and certain subsidiaries. The first group of these programs offered enhanced early retirement benefits to employees age 55 or older with 10 or more years of service. The second group of these programs offered enhanced early retirement benefits to employees age 50 to 54 with 20 or more years of service.

        Since employees electing to participate in the age 55 or older VSERP had to make their elections by the end of 2001, the cost of that program was reflected in 2001. The total cost of that program was approximately $83.8 million ($63.5 million in pension termination benefits, $18.5 million in postretirement benefit costs, and $1.8 million in education and outplacement assistance costs). Of this amount, BGE recorded approximately $13.7 million on its balance sheet as a regulatory asset of its gas business. This amount will be amortized over a 5-year period as provided for in prior Maryland PSC rate orders.

        In connection with the retirement of a significant number of the participants in the nonqualified pension plans we recognized a settlement loss of approximately $10.5 million and a curtailment loss of approximately $5.8 million for those plans in accordance with SFAS No. 88.

        Since the age 50 to 54 programs allow employees to make their elections beginning in January through February 2002, the cost of that program will be reflected in 2002.

78

        We recorded a $133.0 million additional minimum pension liability adjustment as a result of the combination of decreases in the fair value of plan assets due to a declining equity market in 2001 and an increased pension liability primarily due to the VSERP. We charged $59.0 million of this adjustment to an intangible asset included in "Other deferred charges" in our Consolidated Balance Sheets. The remaining $74.0 million, or $44.7 million after-tax, of this adjustment was included in "Accumulated other comprehensive income" in our Consolidated Statements of Common Shareholders' Equity and Consolidated Statements of Capitalization.

        In 2000, we offered a targeted VSERP to provide enhanced early retirement benefits to certain eligible participants in targeted jobs at BGE that elected to retire on June 1, 2000. BGE recorded approximately $10.0 million ($7.6 million for pension termination benefits and $2.4 million for postretirement benefit costs) for employees that elected to participate in the program. Of this amount, BGE recorded approximately $3.0 million on its balance sheet as a regulatory asset of its gas business. We amortize this regulatory asset over a 5-year period. The remaining $7.0 million related to BGE's electric business was charged to expense.

        The cost of the 2001 and 2000 voluntary retirement programs and the settlement or curtailment losses are not included in the tables of net periodic pension and postretirement benefit costs.

Obligations, Assets, and Funded Status

We show the change in the benefit obligations, plan assets, and funded status of the pension and postretirement benefit plans including the effect of the Nine Mile Point acquisition, in the following tables.

	Pension Benefits						Postretirement Benefits
	2001			2000			2001			2000
	(In millions)
Change in benefit obligation
Benefit obligation at January 1	$	1,045.1		$	1,016.7		$	375.9		$	358.7
Service cost		25.8			25.4			8.4			7.7
Interest cost		76.1			73.1			29.2			26.6
Plan participants' contributions		—			—			3.0			2.8
Actuarial loss		42.6			0.8			49.1			40.9
Plan amendments		—			6.7			—			(41.1	)
VSERP charge		63.5			7.6			18.5			2.4
Curtailment		9.7			—			—			—
Settlement		(23.0	)		—			—			—
Nine Mile Point acquisition		91.8			—			15.0			—
Benefits paid		(72.4	)		(85.2	)		(23.9	)		(22.1	)
Benefit obligation at December 31	$	1,259.2		$	1,045.1		$	475.2		$	375.9

	Pension Benefits						Postretirement Benefits
	2001			2000			2001			2000
	(In millions)
Change in plan assets
Fair value of plan assets at January 1	$	1,030.1		$	1,084.9		$	—		$	—
Actual return on plan assets		(42.7	)		3.7			—			—
Employer contribution		39.4			26.7			20.9			19.3
Plan participants' contributions		—			—			3.0			2.8
Benefits paid		(72.4	)		(85.2	)		(23.9	)		(22.1	)
Fair value of plan assets at December 31	$	954.4		$	1,030.1		$	—		$	—

	Pension Benefits						Postretirement Benefits
	2001			2000			2001			2000
	(In millions)
Funded Status
Funded Status at December 31	$	(304.8	)	$	(15.0	)	$	(475.2	)	$	(375.9	)
Unrecognized net actuarial loss		207.8			49.2			107.8			61.4
Unrecognized prior service cost		56.7			59.2			(0.4	)		(0.4	)
Unrecognized transition obligation		—			—			86.9			94.8
Unamortized net asset from adoption of SFAS No. 87		—			(0.2	)		—			—
Pension liability adjustment		(133.0	)		—			—			—
(Accrued) prepaid benefit cost	$	(173.3	)	$	93.2		$	(280.9	)	$	(220.1	)

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Net Periodic Benefit Cost

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

Year Ended December 31,	2001			2000			1999
	(In millions)
Components of net periodic pension benefit cost
Service cost	$	25.8		$	25.4		$	26.1
Interest cost		76.1			73.1			65.3
Expected return on plan assets		(87.5	)		(83.6	)		(76.6	)
Amortization of transition obligation		(0.2	)		(0.2	)		(0.2	)
Amortization of prior service cost		6.5			6.5			2.5
Recognized net actuarial loss		2.8			2.6			10.1
Amount capitalized as construction cost		(2.5	)		(3.4	)		(4.2	)
Net periodic pension benefit cost	$	21.0		$	20.4		$	23.0

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

Year Ended December 31,	2001			2000			1999
	(In millions)
Components of net periodic postretirement benefit cost
Service cost	$	8.4		$	7.7		$	8.6
Interest cost		29.2			26.6			24.4
Amortization of transition obligation		7.9			7.9			11.0
Recognized net actuarial loss		3.3			3.1			1.9
Amount capitalized as construction cost		(14.5	)		(10.8	)		(9.4	)
Net periodic postretirement benefit cost	$	34.3		$	34.5		$	36.5

Assumptions

We made the assumptions below to calculate our pension and postretirement benefit obligations.

	Pension Benefits				Postretirement Benefits
At December 31,
	2001		2000		2001		2000
Discount rate	7.25	%	7.50	%	7.25	%	7.50	%
Expected return on plan assets	9.00		9.00		N/A		N/A
Rate of compensation increase	4.00		4.00		4.00		4.00

        We assumed the health care inflation rates to be:

•

in 2001, 5.7% for Medicare-eligible retirees and 9.5% for retirees not covered by Medicare, and

•

in 2002, 11.0% for both Medicare-eligible retirees and retirees not covered by Medicare.

        After 2002, we assumed inflation rates will decrease to 7.0% in 2003, 6.5% in 2004, 6.0% in 2005, and 5.5% annually after 2005.

        A one-percent increase in the health care inflation rate from the assumed rates would increase the accumulated postretirement benefit obligation by approximately $63.8 million as of December 31, 2001 and would increase the combined service and interest costs of the postretirement benefit cost by approximately $5.9 million annually.

        A one-percent decrease in the health care inflation rate from the assumed rates would decrease the accumulated postretirement benefit obligation by approximately $51.1 million as of December 31, 2001 and would decrease the combined service and interest costs of the postretirement benefit cost by approximately $4.7 million annually.

Other Postemployment Benefits

We provide the following postemployment benefits:

•

health and life insurance benefits to eligible employees who are found to be disabled under our Disability Insurance Plan, and

•

income replacement payments for employees found to be disabled before November 1995 (payments for employees found to be disabled after that date are paid by an insurance company, and the cost is paid by employees).

        The liability for these benefits totaled $48.7 million as of December 31, 2001 and $46.7 million as of December 31, 2000.

        Effective December 31, 1993, we adopted SFAS No. 112, Employers' Accounting for Postemployment Benefits. We deferred, as a regulatory asset (see Note 6), the postemployment benefit liability attributable to our regulated utility business as of December 31, 1993, consistent with the Maryland PSC's orders for postretirement benefits (described earlier in this note).

        We began to amortize the regulatory asset over 15 years beginning in 1998. The Maryland PSC authorized us to reflect this change in our regulated electric and gas base rates to recover the higher costs in 1998.

        We assumed the discount rate for other postemployment benefits to be 5.0% in 2001 and 5.5% in 2000.

Employee Savings Plan Benefits

We, along with several of our subsidiaries, sponsor defined contribution savings plans that are offered to all eligible employees of Constellation Energy and certain employees of our subsidiaries. The Savings Plans are qualified 401(k) plans under the Internal Revenue Code. In a defined contribution plan, the benefits a participant is to receive result from regular contributions to a participant account. Matching contributions to participant accounts are made under these plans. Matching contributions to these plans were:

•

$12.2 million in 2001,

•

$10.8 million in 2000, and

•

$10.4 million in 1999.

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8 Short-Term Borrowings

Our short-term borrowings may include bank loans, commercial paper, and bank lines of credit. Short-term borrowings mature within one year from the date of issuance. We pay commitment fees to banks for providing us lines of credit. When we borrow under the lines of credit, we pay market interest rates.

Constellation Energy

In anticipation of separating our merchant energy business from our other businesses and to fund working capital requirements and capital expenditures, in June 2001, Constellation Energy arranged a $2.5 billion, 364-day revolving credit facility. However, since we canceled prior plans to separate, we used this facility primarily to fund capital expenditures, and working capital requirements, including commercial paper support, for the merchant energy business.

        In June 2001, Constellation Energy also arranged a $380 million, 364-day revolving credit facility to be used primarily to support letters of credit and for other short-term financing needs, including commercial paper support. Constellation Energy also has an existing $188.5 million, multi-year revolving credit facility available for short-term and long-term needs, including support for the issuance of letters of credit.

        Constellation Energy had committed bank lines of credit as described above of $3.1 billion at December 31, 2001 and $565.0 million at December 31, 2000 for short-term financial needs, including support for the issuance of letters of credit. These agreements also support Constellation Energy's commercial paper program. Letters of credit issued under all of our facilities totaled $245.8 million at December 31, 2001 and $297.2 million at December 31, 2000. Constellation Energy had commercial paper outstanding of $954.9 million at December 31, 2001 and $198.7 million at December 31, 2000.

        The weighted-average effective interest rates for Constellation Energy's commercial paper were 3.73% for the year ended December 31, 2001 and 6.31% for 2000.

BGE

BGE had no commercial paper outstanding at December 31, 2001 and $32.1 million at December 31, 2000.

        At December 31, 2001, BGE had unused committed bank lines of credit totaling $243.0 million supporting the commercial paper program compared to $218.0 million at December 31, 2000. BGE has a $25 million revolving credit agreement that is available through 2003. At December 31, 2001 and 2000, BGE did not have any borrowings under the revolving credit agreement. This agreement also supports BGE's commercial paper program.

        The weighted-average effective interest rates for BGE's commercial paper were 2.53% for the year ended December 31, 2001 and 6.36% for 2000.

Other Nonregulated Businesses

Our other nonregulated businesses had short-term borrowings outstanding of $20.1 million at December 31, 2001 and $12.8 million at December 31, 2000. The weighted-average effective interest rates for our other nonregulated businesses' short-term borrowings were 4.20% for the year ended December 31, 2001 and 8.59% for 2000.

9 Long-Term Debt

Long-term debt matures in one year or more from the date of issuance. We summarize our long-term debt in the Consolidated Statements of Capitalization. As you read this section, it may be helpful to refer to those statements.

Constellation Energy

On January 17, 2001, we issued $400.0 million of Mandatorily Redeemable Floating Rate Notes that matured on January 17, 2002.

        On April 11, 2001, we issued $235.0 million of Mandatorily Redeemable Floating Rate Notes that matured on January 17, 2002.

        In 2001, we redeemed several Notes that totaled $700.0 million prior to their maturity for a purchase price equal to 100% of their principal amount, plus accrued interest.

BGE

BGE's First Refunding Mortgage Bonds

BGE's first refunding mortgage bonds are secured by a mortgage lien on all of its assets. The generating assets BGE transferred to subsidiaries of Constellation Energy also remain subject to the lien of BGE's mortgage, along with the stock of Safe Harbor Water Power Corporation and Constellation Enterprises, Inc.

        BGE is required to make an annual sinking fund payment each August 1 to the mortgage trustee. The amount of the payment is equal to 1% of the highest principal amount of bonds outstanding during the preceding 12 months. The trustee uses these funds to retire bonds from any series through

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repurchases or calls for early redemption. However, the trustee cannot call the following bonds for early redemption:

• 71/4% Series, due 2002	• 51/2% Series, due 2004
• 61/2% Series, due 2003	• 71/2% Series, due 2007
• 61/8% Series, due 2003	• 65/8% Series, due 2008

        Holders of the Remarketed Floating Rate Series due September 1, 2006 have the option to require BGE to repurchase their bonds at face value on September 1 of each year. BGE is required to repurchase and retire at par any bonds that are not remarketed or purchased by the remarketing agent. BGE also has the option to redeem all or some of these bonds at face value each September 1.

BGE's Other Long-Term Debt

On May 11, 2001, BGE issued $200.0 million of Floating Rate Reset Notes that matured on February 5, 2002.

        Also on May 11, 2001, BGE redeemed $200.0 million of Floating Rate Notes.

        On December 11, 2001, BGE issued $300.0 million 5.25% Notes, due December 15, 2006.

        On July 1, 2000, BGE transferred $278.0 million of tax-exempt debt to our merchant energy business related to the transferred assets. At December 31, 2001, BGE remains contingently liable for the $276.5 million outstanding balance of this debt.

        On December 20, 2000, BGE issued $173.0 million of 6.75% Remarketable and Redeemable Securities (ROARS) due December 15, 2012. The ROARS contain an option for the underwriters to remarket the ROARS on December 15, 2002. If the underwriters do not elect to remarket the ROARS on that date, then BGE must redeem the ROARS at 100% of the principal amount on December 15, 2002.

        We show the weighted-average interest rates and maturity dates for BGE's fixed-rate medium-term notes outstanding at December 31, 2001 in the following table.

Series	Weighted-Average Interest Rate		Maturity Dates
B	8.77	%	2002-2006
C	7.97		2003
D	6.67		2004-2006
E	6.66		2006-2012
G	6.08		2008

        Some of the medium-term notes include a "put option." These put options allow the holders to sell their notes back to BGE on the put option dates at a price equal to 100% of the principal amount. The following is a summary of medium-term notes with put options.

Series E Notes	Principal		Put Option Dates
(In millions)
6.75%, due 2012	$	60.0	June 2002 and 2007
6.75%, due 2012	$	25.0	June 2004 and 2007
6.73%, due 2012	$	25.0	June 2004 and 2007

BGE Obligated Mandatorily Redeemable Trust Preferred Securities

On June 15, 1998, BGE Capital Trust I (Trust), a Delaware business trust established by BGE, issued 10,000,000 Trust Originated Preferred Securities (TOPrS) for $250 million ($25 liquidation amount per preferred security) with a distribution rate of 7.16%.

        The Trust used the net proceeds from the issuance of the common securities and the preferred securities to purchase a series of 7.16% Deferrable Interest Subordinated Debentures due June 30, 2038 (debentures) from BGE in the aggregate principal amount of $257.7 million with the same terms as the TOPrS. The Trust must redeem the TOPrS at $25 per preferred security plus accrued but unpaid distributions when the debentures are paid at maturity or upon any earlier redemption. BGE has the option to redeem the debentures at any time on or after June 15, 2003 or at any time when certain tax or other events occur.

        The interest paid on the debentures, which the Trust will use to make distributions on the TOPrS, is included in "Interest expense" in our Consolidated Statements of Income and is deductible for income tax purposes.

        BGE fully and unconditionally guarantees the TOPrS based on its various obligations relating to the trust agreement, indentures, debentures, and the preferred security guarantee agreement.

        The debentures are the only assets of the Trust. The Trust is wholly owned by BGE because it owns all the common securities of the Trust that have general voting power.

        For the payment of dividends and in the event of liquidation of BGE, the debentures are ranked prior to preference stock and common stock.

Other Nonregulated Businesses

Revolving Credit Agreement

ComfortLink has a $50 million unsecured revolving credit agreement that matures September 26, 2002. Under the terms of the agreement, ComfortLink has the option to obtain loans at various rates for terms up to nine months. ComfortLink pays a facility fee on the total amount of the commitment. Under this agreement, ComfortLink had outstanding $46.0 million at December 31, 2001 and $34.0 million at December 31, 2000.

        On December 18, 2001, ComfortLink entered into a $25.0 million loan agreement with the Maryland Energy Financing Administration (MEFA). The terms of the loan exactly match the terms of variable rate, tax exempt bonds due December 1, 2031 issued by MEFA for ComfortLink to finance the cost of building a chilled water distribution system. The interest rate on this debt resets weekly. These bonds, and the corresponding loan, can be redeemed at any time at par plus accrued interest while under variable rates. The bonds can also be converted to a fixed rate at ComfortLink's option.

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Mortgage and Construction Loans

Our nonregulated businesses' mortgage and construction loans have varying terms. The following mortgage notes require monthly principal and interest payments:

•

4.25%, due in 2009

•

9.65%, due in 2028

•

8.00%, due in 2033

        The variable rate mortgage notes and construction loans require periodic payment of principal and interest.

Maturities of Long-Term Debt

All of our long-term borrowings mature on the following schedule (includes sinking fund requirements):

Year	Constellation Energy		Nonregulated Business		BGE
	(In millions)
2002	$	635.0	$	85.4	$	519.8
2003		—		86.1		285.6
2004		—		83.7		155.4
2005		300.0		78.4		46.9
2006		—		78.4		464.9
Thereafter		—		357.1		947.7
Total long-term debt at December 31, 2001	$	935.0	$	769.1	$	2,420.3

        At December 31, 2001, BGE had long-term loans totaling $221.5 million that mature after 2002 (including $110.0 million of medium-term notes discussed in this Note under "BGE's Other Long-Term Debt") which contain certain put options under which lenders could potentially require us to repay the debt prior to maturity. Of this amount, $171.5 million could be repaid in 2002 and $50.0 million in 2004. At December 31, 2001, $146.5 million is classified as current portion of long-term debt as a result of these provisions.

        At December 31, 2001, our other nonregulated businesses had long-term loans totaling $20.0 million that mature after 2003 that lenders could potentially require us to repay early. This amount is classified as current portion of long-term debt as a result of these repayment provisions.

Weighted-Average Interest Rates for Variable Rate Debt

Our weighted-average interest rates for variable rate debt were:

Year ended December 31,		2001		2000
Nonregulated Businesses (including Constellation Energy)
	Floating rate notes	4.95	%	6.98	%
	Loans under credit agreements	4.60		6.64
	Mortgage and construction loans	4.39		7.78
	Tax-exempt debt transferred from BGE	3.12		4.26
	Other tax-exempt debt	1.75		—
BGE
	Remarketed floating rate series mortgage bonds	4.49	%	6.59	%
	Floating rate reset notes	4.14		7.27
	Medium-term notes, Series G	—		6.58
	Medium-term notes, Series H	—		6.58

10 Leases

There are two types of leases—operating and capital. Capital leases qualify as sales or purchases of property and are reported in our Consolidated Balance Sheets. Capital leases are not material in amount. All other leases are operating leases and are reported in our Consolidated Statements of Income. We expense all lease payments associated with our regulated utility operations. We present information about our operating leases below.

Outgoing Lease Payments

We, as lessee, lease some facilities and equipment. The lease agreements expire on various dates and have various renewal options.

        Lease expense was:

•

$11.7 million in 2001,

•

$11.3 million in 2000, and

•

$12.2 million in 1999.

        At December 31, 2001, we owed future minimum payments for long-term, noncancelable, operating leases as follows:

Year
	(In millions)
2002	$	9.1
2003		24.1
2004		39.2
2005		37.9
2006		13.3
Thereafter		145.8
Total future minimum lease payments	$	269.4

        The above table includes the operating lease payments for the High Desert project in California through 2006. We are currently leasing and supervising the construction of the High Desert project, a 750 megawatt generating facility in California. The High Desert project uses an off-balance sheet financing structure through a special-purpose entity (SPE) that qualifies as

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an operating lease. The project is scheduled for completion in the summer of 2003.

        Under the terms of the lease, we are required to make payments that represent all or a portion of the lease balance if one of the following events occurs: termination of construction prior to completion or our default under the lease.

        In addition, we may be required to either post cash collateral equal to the outstanding lease balance or we may elect to purchase the property for the outstanding lease balance. At any time during the term of the lease we have the right to pay off the lease and acquire the asset from the lessor. At December 31, 2001, the outstanding lease balance plus other committed expenses was $271.2 million.

        At the conclusion of the lease term in 2006, we have the following options:

•

renew the lease upon approval of the lessors,

•

elect to purchase the property for a price equal to the lease balance at the end of the term, or

•

request the lessor to sell the property.

        If we request the lessor to sell the property, we guarantee the sale proceeds up to approximately 83% of the lease balance. The lease balance at the end of the term is currently estimated to be $600 million, which represents the estimated cost of the project; however, this may vary based on the ultimate cost of construction and interest incurred during the construction period.

11 Commitments, Guarantees, and Contingencies

Commitments

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

•

purchase of electric generating capacity and energy,

•

procurement and delivery of fuels, and

•

capital for construction programs and loans.

        Our merchant energy business has a long-term contract for the purchase of electric generating capacity and energy that expires in 2013. Portions of this contract became uneconomical upon the deregulation of electric generation. Therefore, we recorded a charge and accrued a corresponding liability based on the net present value of the excess of estimated contract costs over the market-based revenues to recover these costs over the remaining term of the contract as discussed in Note 5. At December 31, 2001, the accrued portion of this contract was $10.6 million.

        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 2002 and 2006. 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 2002 and 2021.

        Our merchant energy business also has committed to contribute additional capital for our construction program and to make additional loans to some affiliates, joint ventures, and partnerships in which they have an interest.

        At December 31, 2001, we estimate the future obligations of our merchant energy business in the following table:

	2002		2003		2004		2005		2006		Thereafter		Total
	(In millions)
Purchased capacity and energy	$	16.4	$	16.0	$	15.5	$	15.1	$	15.0	$	98.5	$	176.5
Fuel and transportation		318.1		228.3		99.5		49.1		48.8		17.7		761.5
Capital and loans		81.5		0.8		—		—		—		—		82.3
Total future obligations	$	416.0	$	245.1	$	115.0	$	64.2	$	63.8	$	116.2	$	1,020.3

        Our regulated gas business enters into various long-term contracts for the procurement, transportation, and storage of gas. These contracts are recoverable under BGE's gas cost adjustment clause discussed in Note 1.

        BGE Home Products & Services has gas purchase commitments of $35.0 million in 2002 and $2.2 million in 2003 related to its gas program.

Sale of Receivables

BGE and BGE Home Products & Services have agreements to sell on an ongoing basis an undivided interest in a designated pool of customer receivables. Under the agreements, BGE can sell up to a total of $25 million, and BGE Home Products & Services can sell up to a total of $50 million. Under the terms of the agreements, the buyer of the receivables has limited recourse against these entities. BGE and BGE Home Products & Services have recorded reserves for credit losses. At December 31, 2001, BGE had sold $8.1 million and BGE Home Products & Services had sold $42.5 million of receivables under these agreements.

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Guarantees

At December 31, 2001, Constellation Energy issued guarantees in an amount up to $1,682.4 million related to credit facilities and contractual performance of certain of its nonregulated subsidiaries, including $600 million relating to the High Desert project. The actual subsidiary liabilities related to these guarantees totaled $369.9 million at December 31, 2001.

        At December 31, 2001, Constellation Nuclear guaranteed the $388.1 million sellers' note that financed the acquisition of Nine Mile Point. This guarantee contains covenant provisions that require Constellation Nuclear to maintain a net worth of at least $500 million and a ratio of current assets to current liabilities of at least 1.1.

        At December 31, 2001, our merchant energy business had other guaranteed outstanding loans and letters of credit of certain power projects totaling $26.7 million.

        At December 31, 2001, our other nonregulated businesses had guaranteed outstanding loans and letters of credit of real estate projects totaling $15.9 million.

        BGE guarantees two-thirds of certain debt of Safe Harbor Water Power Corporation. At December 31, 2001, Safe Harbor Water Power Corporation had outstanding debt of $20 million. The maximum amount of BGE's guarantee is $13.3 million. Additionally at December 31, 2001, BGE guaranteed the TOPrS of $250.0 million as discussed in Note 9.

        We assess the risk of loss from these guarantees to be minimal.

Environmental Matters

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

•

air quality,

•

water quality,

•

chemical and waste management and disposal, and

•

other environmental matters.

        The development (involving site selection, environmental assessments, and permitting), construction, acquisition, and operation of electric generating, transmission, and distribution facilities are subject to extensive federal, state, and local environmental and land use laws and regulations. From the beginning phases of siting and developing, to the ongoing operation of existing or new electric generating, transmission, and distribution facilities, our activities involve compliance with diverse laws and regulations that address emissions and impacts to air and water, special, protected, and cultural resources (such as wetlands, endangered species, and archeological/historical resources), chemical and waste handling, and noise impacts.

        Our activities require complex and often lengthy processes to obtain approvals, permits, or licenses for new, existing, or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires preparation of release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or their operation, as required.

        We discuss the significant matters below.

Clean Air Act

The Clean Air Act affects both existing generating facilities and new projects. The Clean Air Act and many state laws require significant reductions in SO₂ (sulfur dioxide) and NO_X (nitrogen oxide) emissions that result from burning fossil fuels. The Clean Air Act also contains other provisions that could materially affect some of our projects. Various provisions may require permits, inspections, or installation of additional pollution control technology. Certain of these provisions are described in more detail below. Since our generation portfolio is diverse, both in the mix of fuels used to generate electricity, as well as in the age of various facilities, the Clean Air Act requirements have different impacts in terms of compliance costs for each of our projects. Many of these compliance costs may be substantial, as described in more detail below. In addition, the Clean Air Act contains many enforcement tools, ranging from broad investigatory powers to civil, criminal, and administrative penalties and citizen suits. These enforcement provisions also include enhanced monitoring, recordkeeping, and reporting requirements for both existing and new facilities.

        The Clean Air Act creates a marketable commodity called an SO₂ "allowance." All non-exempt facilities over 25 megawatts that emit SO₂ must obtain allowances in order to operate after 1999. Each allowance gives the owner the right to emit one ton of SO₂. All non-exempt existing facilities have been allocated allowances based on a facility's past production and the statutory emission reduction goals. If additional allowances are needed for new facilities, they can be purchased from facilities having excess allowances or from SO₂ allowance banks. Our projects comply with the SO₂ allowance caps through the purchase of allowances, use of emission control devices, or by qualifying for exemptions. We believe that the additional costs of obtaining allowances needed for future generation projects should not materially affect our ability to build, acquire, and operate them.

        The Clean Air Act also requires states to impose annual operating permit fees. These fees are based on the tons of pollutants emitted from a generating facility and vary based on the type of facility. For example, fees will typically be greater for coal-fired plants than for natural gas-fired plants. Our portfolio includes coal-fired plants and gas-fired plants, as well as plants using renewable energy sources such as solar and geothermal, which have far less emissions. The fees do not significantly increase our costs.

        The Ozone Transport Assessment Group, composed of state and local air regulatory officials from the 37 Mid-Western and Eastern states, has recommended additional NO_X emission reductions that go beyond current federal standards. These recommendations include reductions from utility and industrial boilers during the summer ozone season.

        As a result of the Ozone Transport Assessment Group's recommendations, on October 27, 1998, the Environmental Protection Agency (EPA) issued a rule requiring 22 Eastern states and the District of Columbia to reduce emissions of NO_X (a precursor of ozone). Among other things, the EPA's rule establishes an ozone season, which runs from May through September, and a NO_X emission budget for each state, including Maryland and Pennsylvania. The EPA rule requires states to

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implement controls sufficient to meet their NO_X budget by May 30, 2004. Coal-fired power plants are a principal target of NO_X reductions under this initiative, however, some of our newer coal-fired plants may already meet the EPA expectations and will not require the same amount of capital expenditures.

        Many of the generation facilities are subject to NO_X reduction requirements under the EPA rule including those located in Maryland and Pennsylvania. This regulation affects both new and existing facilities causing additional capital investment. At the Brandon Shores facility we have installed and at our Wagner facility we are installing, emission reduction equipment by May 2002 to meet Maryland regulations issued pursuant to EPA's rule. The owners of the Keystone plant in Pennsylvania are installing emissions reduction equipment by 2003 to meet Pennsylvania regulations issued pursuant to EPA's rule. We estimate that the equipment needed at these plants will cost approximately $290 million. Through December 31, 2001, we have spent approximately $200 million.

        Over the past two years, the EPA and several states have filed suits against a number of coal-fired power plants in Mid-Western and Southern states alleging violations of the deterioration prevention and non-attainment provisions of the Clean Air Act's new source review requirements. In 2000, using its broad investigatory powers, the EPA requested information relating to modifications made to our Brandon Shores, Crane, and Wagner plants in Baltimore, Maryland. The EPA also sent similar, but narrower, information requests to two of our newer Pennsylvania waste-coal burning plants. We have responded to the EPA and are waiting to see if the EPA takes any further action. This information is to determine compliance with the Clean Air Act and state implementation plan requirements, including potential application of federal New Source Performance Standards.

        In general, such standards can require the installation of additional air pollution control equipment upon the major modification of an existing plant. Although there have not been any new source review-related suits filed against our facilities, there can be no assurance that any of them will not be the target of an action in the future. Based on the levels of emissions control that the EPA and/or states are seeking in these new source review enforcement actions, we believe that material additional costs and penalties could be incurred, and/or planned capital expenditures could be accelerated, if the EPA was successful in any future actions regarding our facilities.

        The Clean Air Act requires the EPA to evaluate the public health impacts of emissions of mercury, a hazardous air pollutant, from coal-fired plants. The EPA has decided to control mercury emissions from coal-fired plants. Compliance could be required by approximately 2007. Final regulations are expected to be issued in 2004 and would affect all coal-fired boilers. The cost of compliance could be material.

        Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. The related Kyoto Protocol was signed by the United States but has not yet been ratified by the U.S. Senate. Future initiatives on this issue and the ultimate effects of the Kyoto Protocol on us are unknown at this time. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies. Fossil fuel-fired power plants, however, are significant sources of carbon dioxide emissions, a principal greenhouse gas. Therefore, our compliance costs with any mandated federal greenhouse gas reductions in the future could be significant.

Waste Disposal

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

        We can, however, estimate that our current 15.47% share of the reasonably possible cleanup costs at one of these sites, Metal Bank of America, a metal reclaimer in Philadelphia, could be as much as $2.3 million higher than amounts we have recorded as a liability on our Consolidated Balance Sheets. This estimate is based on a Record of Decision issued by the EPA.

        Also, we are coordinating investigation of several sites where gas was manufactured in the past. The investigation of these sites includes reviewing possible actions to remove coal tar. In late December 1996, we signed a consent order with the Maryland Department of the Environment (MDE) that required us to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. We submitted the required remedial action plans and they were approved by the MDE. Based on the remedial action plans, the costs we consider to be probable to remedy the contamination are estimated to total $47 million. We have recorded these costs as a liability on our Consolidated Balance Sheets and have deferred these costs, net of accumulated amortization and amounts we recovered from insurance companies, as a regulatory asset. Because of the results of studies at these sites, it is reasonably possible that these additional costs could exceed the amount we recognized by approximately $14 million. We discuss this further in Note 6. Through December 31, 2001, we have spent approximately $37 million for remediation at this site.

        We do not expect the cleanup costs of the remaining sites to have a material effect on our financial results.

Litigation

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

California

Baldwin Associates, Inc. v. Gray Davis, Governor of California and 22 other defendants (including Constellation Power Development, Inc., a subsidiary of Constellation Power, Inc.)—This class action lawsuit was filed on October 5, 2001 in the Superior Court, County of San Francisco. The action seeks damages of $43 billion, recession and reformation of approximately 38 long-term power purchase contracts, and an injunction against improper spending by the state of California. Constellation Power Development, Inc. is named as a defendant but does not have a power purchase agreement with the State of California. However, our High Desert Power Project does have a power

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purchase agreement with the California Department of Water Resources. We believe this case is without merit. However, we cannot predict the timing, or outcome, of it or its possible effect on our financial results.

Employment Discrimination

Miller, et. al v. Baltimore Gas and Electric Company, et al.—This action was filed on September 20, 2000 in the U.S. District Court for the District of Maryland. Besides BGE, Constellation Energy Group, Constellation Nuclear, and Calvert Cliffs Nuclear Power Plant are also named defendants. The action seeks class certification for approximately 150 past and present employees and alleges racial discrimination at Calvert Cliffs Nuclear Power Plant. The amount of damages is unspecified, however the plaintiffs seek back and front pay, along with compensatory and punitive damages. The Court scheduled a briefing process for the motion to certify the case as a class action suit for the beginning of 2003. We believe this case is without merit. However, we cannot predict the timing, or outcome, of it or its possible effect on our, or BGE's, financial results.

Asbestos

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

        The first type is direct claims by individuals exposed to asbestos. BGE is involved in these claims with approximately 70 other defendants. Approximately 545 individuals that were never employees of BGE each claim $6 million in damages ($2 million compensatory and $4 million punitive). These claims were filed in the Circuit Court for Baltimore City, Maryland in the summer of 1993. BGE does not know the specific facts necessary to estimate its potential liability for these claims. The specific facts BGE does not know include:

•

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

•

the names of the plaintiff's employers, and

•

the date on which the exposure allegedly occurred.

        To date, 36 of these cases were settled for amounts that were not significant.

        The second type is claims by one manufacturer—Pittsburgh Corning Corp. (PCC)—against BGE and approximately eight others, as third-party defendants. On April 17, 2000, PCC declared bankruptcy, and BGE does not expect PCC to prosecute these claims.

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

•

the identity of BGE facilities containing asbestos manufactured by the manufacturer,

•

the relationship (if any) of each of the individual plaintiffs to BGE,

•

the settlement amounts for any individual plaintiffs who are shown to have had a relationship to BGE, and

•

the dates on which/places at which the exposure allegedly occurred.

        Until the relevant facts for both types of claims are determined, BGE is unable to estimate what its liability, if any, 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 liability could be material.

Asset Transfer Order

On July 6, 2000, the Mid-Atlantic Power Supply Association (MAPSA) and Shell Energy LLC filed, in the Circuit Court for Baltimore City, a petition for review and a delay of the Maryland PSC's order approving the transfer of BGE's generation assets issued on June 19, 2000. The Court denied MAPSA's request for a delay on August 4, 2000, and after a hearing on the petition on August 23, 2000 issued an order on September 29, 2000 upholding the Maryland PSC's order on the asset transfer. On October 27, 2000, MAPSA filed an appeal with the Maryland Court of Special Appeals challenging the September 29, 2000 order issued by the Circuit Court. The Court of Special Appeals heard oral arguments on the appeal on September 7, 2001. We also believe that this petition is without merit. However, we cannot predict the timing or outcome of this case, which could have a material adverse effect on our, and BGE's, financial results.

Restructuring Order

In early December 1999, MAPSA, Trigen-Baltimore Energy Corporation, and Sweetheart Cup Company, Inc. filed appeals of the Restructuring Order, which were consolidated in the Baltimore City Circuit Court. MAPSA also filed a motion to delay implementation of the Restructuring Order, pending a decision on the merits of the appeals by the court.

        On April 21, 2000, the Circuit Court dismissed MAPSA's appeal based on a lack of standing (the right of a party to bring a lawsuit to court) and denied its motion for a delay of the Restructuring Order. However, MAPSA filed an appeal of this decision. On May 24, 2000, the Circuit Court dismissed both the Trigen and Sweetheart Cup appeals.

        MAPSA subsequently filed several appeals with the Maryland Court of Special Appeals, the Maryland Court of Appeals, and the Baltimore City Circuit Court. The effect of the appeals was to delay the implementation of customer choice in BGE's service territory.

        However, on August 4, 2000, the delay was rescinded and BGE retroactively adjusted its rates as if customer choice had been implemented July 1, 2000.

        On September 29, 2000, the Baltimore City Circuit Court issued an order upholding the Restructuring Order.

        On October 27, 2000, MAPSA filed an appeal with the Maryland Court of Special Appeals challenging the

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September 29, 2000 order issued by the Circuit Court. The Court of Special Appeals heard oral arguments on the appeal on September 7, 2001. We believe that this petition is without merit. However, we cannot predict the timing or outcome of this case, which could have a material adverse effect on our, and BGE's, financial results.

Nuclear Insurance

We maintain nuclear insurance coverage for Calvert Cliffs and Nine Mile Point in four program areas: liability, worker radiation claims, property, and accidental outage. However, these policies have certain industry standard exclusions, such as ordinary wear and tear and war. Terrorist acts, while not excluded from the property and accidental outage policies, are covered as a common occurrence, meaning that if terrorist acts occur against one or more commercial nuclear power plants insured by our insurance company within a 12-month period, they will be treated as one event and the owners of the plants will share one full limit of each type of policy (currently $3.24 billion). Claims that arise out of terrorist acts are also covered by our nuclear liability and worker radiation policies. However, these policies are subject to one industry aggregate limit (currently $200 million) for the risk of terrorism. Unlike the property and accidental outage policies, however, an industry-wide retrospective assessment program applies above the industry limit (see below for an explanation of this program).

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

Liability Insurance

Pursuant to the Price-Anderson Act, we are required to insure against public liability claims resulting from nuclear incidents to the full limit of approximately $9.5 billion. We have purchased the maximum available commercial insurance of $200 million, and the remaining $9.3 billion is provided through mandatory participation in an industry-wide retrospective assessment program. Under this retrospective assessment program, we can be assessed up to $352.4 million per incident, payable at no more than $40 million per incident per year. This assessment also applies in excess of our worker radiation claims insurance and is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose additional revenue-raising measures to pay claims.

        Some of the provisions of this Act expire in August 2002, and the Act is subject to change if those provisions are extended. While we expect these provisions to be extended, we do not know what impact any changes to the Act may have on us.

Worker Radiation Claims Insurance

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

•

Nuclear worker claims reported on or after January 1, 1998 are covered by a new insurance policy with an annual industry aggregate limit of $200 million for radiation injury claims against all those insured by this policy.

•

All nuclear worker claims reported prior to January 1, 1998 are still covered by the old policy. Insureds under the old policies, with no current operations, are not required to purchase the new policy described above, and may still make claims against the old policies through 2007. If radiation injury claims under these old policies exceed the policy reserves, all policyholders could be retroactively assessed, with our share being up to $6.3 million.

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

Property Insurance

Our policies provide $500 million in primary and an additional $2.25 billion in excess coverage for property damage, decontamination, and premature decommissioning liability for Calvert Cliffs or Nine Mile Point. If accidents at any insured plants cause a shortfall of funds at the industry mutual insurance company, all policyholders could be assessed, with our share being up to $56.2 million.

Accidental Outage Insurance

Our policies provide indemnification on a weekly basis resulting from an accidental outage of a nuclear unit. Initial coverage begins after a 12-week deductible period and continues at 100% of the weekly indemnity limit for 52 weeks and 80% of the weekly indemnity limit for the next 110 weeks. Our coverage is up to $490.0 million per unit at Calvert Cliffs, $335.4 million for Unit 1 of Nine Mile Point, and $412.6 million for Unit 2 of Nine Mile Point. This amount can be reduced by up to $98.0 million per unit at Calvert Cliffs and $82.5 million for Nine Mile Point if an outage at either plant is caused by a single insured physical damage loss.

California Power Purchase Agreements

Our merchant energy business has $296.4 million invested in operating power projects of which our ownership percentage represents 146 megawatts of electricity that are sold to Pacific Gas & Electric (PGE) and to Southern California Edison (SCE) in California under power purchase agreements. Our merchant energy business was not paid in full for its sales from these plants to the two utilities from November 2000 through early April 2001. At December 31, 2001, our portion of the amount due for unpaid power sales from these utilities was

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approximately $45 million. We recorded reserves of approximately 20% of this amount.

        These projects entered into agreements with PGE and SCE that provide for five-year fixed-price payments averaging $53.70 per megawatt-hour plus the stated capacity payments in the original Interim Standard Offer No. 4 (SO4) contracts. These agreements also provide for the payment of all past due amounts plus interest, which the projects expect to collect within the next two years. The SCE agreement to pay these past due amounts is contingent on SCE making certain payments to other creditors.

        As a result of ongoing litigation before the FERC regarding sales into the spot markets of the California Independent System Operator and Power Exchange, we may be required to pay refunds of between $3 and $4 million for transactions that we entered into with these entities for the period between October 2000 and June 2001. While the process at FERC is ongoing, FERC has indicated that we will have the ability to reduce the potential refund amount in order to recover outstanding receivables we are owed. FERC also has indicated that it will consider adjustments to the refund amount to the extent we can demonstrate that its refund methodology resulted in an overall revenue shortfall for our transactions in these markets during the refund period.

12 Risk Management Activities and Fair Value of Financial Instruments

Risk Management Activities

In 2001, we entered into forward starting interest rate swap contracts to manage a portion of our interest rate exposure for anticipated long-term borrowings to refinance our outstanding commercial paper obligations and maturing long-term debt. The swaps have notional or contract amounts that total $800 million with an average rate of 4.9% and expire in the first quarter of 2002. The notional amounts of the contracts do not represent amounts that are exchanged by the parties and are not a measure of our exposure to market or credit risks. The notional amounts are used in the determination of the cash settlements under the contracts. At December 31, 2001, the fair value of these swaps was an unrealized pre-tax gain of $36.3 million.

        At December 31, 2001, these swaps were designated as cash-flow hedges under SFAS No. 133. We recorded this unrealized gain in "Other current assets" in our Consolidated Balance Sheets and "Accumulated other comprehensive income," net of associated deferred income tax effects, in our Consolidated Statements of Common Shareholders' Equity and Consolidated Statements of Capitalization. Any gain or loss on the hedges will be reclassified from "Accumulated other comprehensive income" into "Interest expense" and be included in earnings during the periods in which the interest payments being hedged occur.

        In 2002, we entered into additional forward starting interest rate swaps with notional amounts that total $700 million. These swaps have an average rate of 5.9% and expire in the first quarter of 2002.

        Our power marketing operation manages the commodity price risk of our electric generation operations as part of its overall portfolio. In order to manage this risk, our merchant energy business may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of electricity and purchases of fuel as discussed in Note 1.

        At December 31, 2001, our merchant energy business had designated certain fixed-price forward electricity sale contracts as cash-flow hedges of forecasted sales of electricity for the years 2002 through 2010 under SFAS No. 133.

        At December 31, 2001, our merchant energy business recorded net unrealized pre-tax gains of $76.5 million on these hedges, net of associated deferred income tax effects, in "Accumulated other comprehensive income." We expect to reclassify $5.7 million of net pre-tax gains on cash-flow hedges from "Accumulated other comprehensive income" into earnings during the next twelve months based on the market prices at December 31, 2001. However, the actual amount reclassified into earnings could vary from the amounts recorded at December 31, 2001 due to future changes in market prices. In 2001, there was no hedge ineffectiveness recognized in earnings.

        At December 31, 2000, our merchant energy business recorded deferred pre-tax hedge losses of $58.3 million in "Other deferred charges" in our Consolidated Balance Sheets for the fixed-price forward electricity sale contracts designated as a hedge of forecasted sales of electricity. We reclassified these deferred hedge losses, net of associated deferred income tax effects, to "Accumulated other comprehensive income" upon the adoption of SFAS No. 133, in the first quarter of 2001.

Fair Value of Financial Instruments

The fair value of a financial instrument represents the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Significant differences can occur between the fair value and carrying amount of financial instruments that are recorded at historical amounts. We use the following methods and assumptions for estimating fair value disclosures for financial instruments:

•

cash and cash equivalents, net accounts receivable, other current assets, certain current liabilities, short-term borrowings, current portion of long-term debt, and certain deferred credits and other liabilities: because of their short-term nature, the amounts reported in our Consolidated Balance Sheets approximate fair value,

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•

investments and other assets where it was practicable to estimate fair value: the fair value is based on quoted market prices where available, and

•

for long-term debt: the fair value is based on quoted market prices where available or by discounting remaining cash flows at current market rates.

        We show the carrying amounts and fair values of financial instruments included in our Consolidated Balance Sheets in the following table, and we describe some of the items separately later in this section.

At December 31,		2001				2000
		Carrying Amount		Fair Value		Carrying Amount		Fair Value
		(In millions)
Investments and other assets for which it is:
	Practicable to estimate fair value	$	1,144.9	$	1,144.9	$	349.8	$	349.8
	Not practicable to estimate fair value		25.8		N/A		32.7		N/A
Fixed-rate long-term debt			2,945.3		3,069.6		2,734.1		2,819.9
Variable-rate long-term debt			1,179.1		1,179.1		1,331.8		1,331.8

        It was not practicable to estimate the fair value of investments held by our nonregulated businesses in several financial partnerships that invest in nonpublic debt and equity securities. This is because the timing and amount of cash flows from these investments are difficult to predict. We report these investments at their original cost in our Consolidated Balance Sheets.

        The investments in financial partnerships totaled $25.8 million at December 31, 2001 and $32.7 million at December 31, 2000, representing ownership interests up to 11%. The total assets of all of these partnerships totaled $5.4 billion at December 31, 2000 (which is the latest information available).

Guarantees

It was not practicable to determine the fair value of certain loan guarantees of Constellation Energy and its subsidiaries. Constellation Energy guaranteed outstanding debt of $47.9 million at December 31, 2001 and $341.0 million at December 31, 2000.

        Our merchant energy business guaranteed outstanding debt totaling $414.8 million at December 31, 2001 and $33.6 million at December 31, 2000.

        Our other nonregulated businesses guaranteed outstanding debt totaling $15.9 million at December 31, 2001 and $16.5 million at December 31, 2000.

        BGE guaranteed outstanding debt of $263.3 million at December 31, 2001 and 2000.

        We do not anticipate that we will need to fund these guarantees.

13 Stock-Based Compensation

As permitted by SFAS No. 123, Accounting for Stock-Based Compensation, we measure our stock-based compensation in accordance with Accounting Principles Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, and related interpretations.

        Under our existing long-term incentive plans, we can issue awards that include stock options and performance-based restricted stock to officers and key employees. Under the plans, we can issue up to a total of 6,000,000 shares for these awards.

Stock Options

In May 2000, our Board of Directors approved the issuance of nonqualified stock options. Options have been granted at prices not less than the market value of the stock at the date of grant, generally become exercisable ratably over a three-year period beginning one year from the date of grant, and expire ten years from the date of grant. In accordance with APB No. 25, no compensation expense is recognized for the stock option awards. Summarized information for our stock option awards is as follows:

		2001					2000
		Shares		Weighted- Average Exercise Price			Shares		Weighted- Average Exercise Price
		(In thousands, except per share amounts)
Outstanding, beginning of year		2,420		$	34.65		—		$	—
	Granted	1,015			25.08		2,462			34.64
	Exercised	(512	)		(34.25	)	—			—
	Cancelled/ Expired	(277	)		(37.74	)	(42	)		(34.25	)
Outstanding, end of year		2,646		$	30.73		2,420		$	34.65
Exercisable, end of year		235		$	34.25		—			—
Weighted-average fair value per share of options granted				$	9.27				$	5.60

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        The following table summarizes information about stock options outstanding at December 31, 2001 (shares in thousands):

Plan Year	Exercise Prices		Number Outstanding	Weighted-Average Remaining Contractual Life	Number Exercisable
2001	$	25.08	1,015	9.9	—
2000	$	34.25	1,631	8.4	235

Performance-Based Restricted Stock Awards

In addition, we issue common stock based on meeting certain performance and service goals over a three to five year period. This stock vests to participants at various times ranging from three to five years or less. In accordance with APB No. 25, we recognize compensation expense for our restricted stock awards using the variable accounting method. In 2001, due to non-attainment of performance criteria, we recorded a credit to compensation expense of $10.1 million. We recorded compensation expense of $16.3 million for 2000 and $10.5 million for 1999. Summarized share information for our restricted stock awards is as follows:

		2001			2000			1999
		(In thousands, except per share amounts)
Outstanding, beginning of year			377			323			350
	Granted		87			353			358
	Released to participants		—			(277	)		(362	)
	Cancelled		(29	)		(22	)		(23	)
Available for grant, end of year			435			377			323
Weighted-average fair value restricted stock granted		$	35.24		$	32.89		$	28.61

Pro-forma Information

Disclosure of pro-forma information regarding net income and earnings per share is required under SFAS No. 123, which uses the fair value method. The fair values of our stock-based awards were estimated as of the date of grant using the Black-Scholes option pricing model based on the following weighted-average assumptions:

	2001		2000
Risk-free interest rate	4.79	%	6.37	%
Expected life (in years)	5.0		10.0
Expected market price volatility factors	41.3	%	21.0	%
Expected dividend yields	1.8	%	5.7	%

        Had compensation cost for these plans been recognized under the fair value method, net income and basic and diluted earnings per share amounts would have been as follows:

		2001
(In millions, except per share amounts)
Pro-forma net income		$	87.2
Pro-forma earnings per share:
	Basic	$	.54
	Diluted	$	.54

        The effect of applying SFAS No. 123 to our stock-based awards results in net income and earnings per share that are not materially different from amounts reported for the year ended December 31, 2000.

14 Acquisition of Nine Mile Point

On November 7, 2001, we completed our purchase of Nine Mile Point located in Scriba, New York. Nine Mile Point consists of two boiling-water reactors. Unit 1 is a 609-megawatt reactor that entered service in 1969. Unit 2 is a 1,148-megawatt reactor that began operation in 1988.

        Nine Mile Point Nuclear Station, LLC, a subsidiary of Constellation Nuclear, purchased 100 percent of Nine Mile Point Unit 1 and 82 percent of Unit 2. Approximately one-half of the purchase price, or $380 million, in addition to settlement costs of $2.7 million, was paid at closing. The remainder is being financed through the sellers in a note to be repaid over five years with an interest rate of 11.0%. This note may be prepaid at any time without penalty. The sellers also transferred to us approximately $442 million in decommissioning funds. As a result of this purchase, we own 1,550 megawatts of Nine Mile Point's 1,757 megawatts of total generating capacity.

        Niagara Mohawk Power Corporation was the sole owner of Nine Mile Point Unit 1. The co-owners of Unit 2 who sold their interests are: Niagara Mohawk (41 percent), New York State Electric and Gas (18 percent), Rochester Gas & Electric Corporation (14 percent), and Central Hudson Gas & Electric Corporation (9 percent). The Long Island Power Authority will continue to own 18 percent of Unit 2.

        We will sell 90 percent of our share of Nine Mile Point's output back to the sellers at an average price of nearly $35 per megawatt-hour for approximately 10 years under power purchase agreements. The contracts for the output are on a unit contingent basis (if the output is not available because the plant

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is not operating, there is no requirement to provide output from other sources).

Nine Mile Point Net Assets Acquired

At November 7, 2001
	(In millions)
Current Assets	$	135.4
Nuclear Decommissioning Trust Fund		441.7
Net Property, Plant and Equipment		292.6
Intangible Assets (details below)		38.7
Total Assets Acquired		908.4
Current Liabilities		16.9
Deferred Credits and Other Liabilities		120.7
Net Assets Acquired		770.8
Note to Sellers		388.1
Total cash paid	$	382.7

        The intangible assets acquired consist of the following:

Description	Amount		Weighted- Average Useful Life
	(In millions)		(In years)
Operating procedures and manuals	$	23.4	10
Permits and licenses		12.9	27
Software		2.4	5
Total intangible assets	$	38.7

        In 2002, Niagara Mohawk, or its successor, will provide funds equal to the net pension obligation of Nine Mile Point employees following a more precise estimate of this obligation. Refer to Note 7 for additional information.

15 Related Party Transactions—BGE

Income Statement

Under the Restructuring Order, BGE is providing standard offer service to customers at fixed rates over various time periods during the transition period, July 1, 2000 to June 30, 2006, for those customers that do not choose an alternate supplier. Constellation Power Source is under contract to provide BGE with the energy and capacity required to meet its standard offer service obligations for the first three years of the transition period, and 90% of the energy and capacity for the final three years (July 1, 2003—June 30, 2006) of the transition period. The cost of BGE's purchased energy from nonregulated affiliates of Constellation Energy to meet its standard offer service obligation was $1,150.1 million and $581.0 million for the years ended December 31, 2001 and 2000, respectively.

        In addition, BGE receives charges from Constellation Energy for certain corporate functions. Certain costs are directly assigned to BGE. We allocate other corporate function costs based on a total percentage of expected use by BGE. Management believes this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity. These costs were $18.8 million and $21.6 million for the years ended December 31, 2001 and 2000, respectively.

Balance Sheet

As a result of the deregulation of electric generation, BGE transferred its generation assets to nonregulated affiliates of Constellation Energy effective July 1, 2000. In conjunction with this transfer, Constellation Power Source Generation, Inc. issued approximately $366 million in unsecured promissory notes to BGE. All of these notes have been repaid by Constellation Power Source Generation, Inc. The proceeds were used to service current maturities of certain BGE long-term debt.

        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. Under this arrangement, BGE had invested $439.1 million at December 31, 2001 and was neither borrowed nor invested at December 31, 2000.

        Amounts related to corporate functions performed at the Constellation Energy holding company, BGE's purchases to meet its standard offer service obligation, and BGE's charges to Constellation Energy and its nonregulated affiliates for certain services it provides them result in intercompany balances on BGE's Consolidated Balance Sheets.

        Management believes its allocation methods are reasonable and approximate the costs that would be charged to unaffiliated entities.

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16 Quarterly Financial Data (Unaudited)

Our quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair presentation. Our utility business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.

2001 Quarterly Data—Constellation Energy

		Revenue		Income from Operations			Earnings Applicable to Common Stock			Earnings Per Share of Common Stock
		(In millions, except per-share amounts)
Quarter Ended
	March 31	$	1,147.1	$	235.0		$	111.8		$	0.74
	June 30		843.2		171.0			75.6			0.46
	September 30		1,036.1		317.5			163.6			1.00
	December 31		901.9		(365.7	)		(260.1	)		(1.59	)
Year Ended
	December 31	$	3,928.3	$	357.8		$	90.9		$	0.57

2001 Quarterly Data—BGE

		Revenue		Income from Operations		Earnings Applicable to Common Stock
		(In millions)
Quarter Ended
	March 31	$	849.9	$	141.1	$	55.1
	June 30		607.2		75.0		19.9
	September 30		701.3		80.3		23.8
	December 31		562.3		15.4		(14.7	)
Year Ended
	December 31	$	2,720.7	$	311.8	$	84.1

First quarter results include:

Constellation Energy

•

a $8.5 million after-tax gain for the cumulative effect of adopting SFAS No. 133.

Fourth quarter results include:

Constellation Energy and BGE

•

workforce reduction costs for BGE employees of $34.4 million after-tax (see Note 2), and

Constellation Energy

•

workforce reduction costs, contract termination related costs, and impairment losses and other costs totaling an additional $300.4 million after-tax (see Note 2).

2000 Quarterly Data—Constellation Energy

		Revenue		Income from Operations		Earnings Applicable to Common Stock		Earnings Per Share of Common Stock
		(In millions, except per-share amounts)
Quarter Ended
	March 31	$	994.0	$	184.6	$	72.1	$	0.48
	June 30		866.6		132.1		39.6		0.26
	September 30		968.6		313.4		147.5		0.98
	December 31		1,023.3		212.5		86.1		0.57
Year Ended
	December 31	$	3,852.5	$	842.6	$	345.3	$	2.30

2000 Quarterly Data—BGE

		Revenue		Income from Operations		Earnings Applicable to Common Stock
		(In millions)
Quarter Ended
	March 31	$	719.7	$	134.0	$	50.9
	June 30		658.1		127.0		49.1
	September 30		688.5		65.2		10.0
	December 31		680.5		86.2		20.3
Year Ended
	December 31	$	2,746.8	$	412.4	$	130.3

First quarter results include:

Constellation Energy and BGE

•

a $2.5 million after-tax expense for BGE Employees that elected to participate in a VSERP (see Note 2), and

•

$37.5 million in amortization expense for the reduction of our generating plants associated with the Restructuring Order.

Second quarter results include:

Constellation Energy and BGE

•

a $1.7 million after-tax expense for BGE Employees that elected to participate in a VSERP (see Note 2),

•

$37.5 million in amortization expense for the reduction of our generating plants associated with the Restructuring Order, and

Constellation Energy

•

a $15.0 million after-tax deregulation transition cost to Goldman Sachs incurred by our power marketing operation to provide BGE's standard offer service requirements.

The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and dilution as a result of issuing common shares during the year.

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

93

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

PART III

BGE meets the conditions set forth in General Instruction I(1)(a)and (b) of Form 10-K for a reduced disclosure format. Accordingly, all items in this section related to BGE are not presented.

Item 10. Directors and Executive Officers of the Registrant

The information required by this item with respect to directors is set forth under Election of Constellation Energy Directors in the Proxy Statement and is incorporated herein by reference.

        The information required by this item with respect to executive officers of Constellation Energy Group, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, is set forth in Item 4 of Part I of this Form 10-K under Executive Officers of the Registrant.

        The information required by this item with respect to compliance with Section 16(a) of the Securities Exchange Act of 1934 is set forth under Section 16(a) Beneficial Ownership Reporting Compliance in the proxy statement and is incorporated herein by reference.

Item 11. Executive Compensation

The information required by this item is set forth under Directors' Compensation, Compensation Committee Interlocks and Insider Participation, Executive Compensation, Common Stock Performance Graph and Report of Committee on Management on Executive Compensation in the Proxy Statement and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management

The information required by this item is set forth under Security Ownership in the Proxy Statement and is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions

Mr. Michael J. Wallace, prior to becoming President of Constellation Generation Group on January 1, 2002, was a Managing Member and Managing Director and greater than 10% owner of Barrington Energy Partners, LLC. Upon becoming President of Constellation Generation Group, Mr. Wallace terminated his affiliation with Barrington, and no longer holds any ownership interest in it. Barrington Energy Partners provided consulting services to Constellation Energy and its subsidiary, Constellation Nuclear during 2001, and is continuing to do so during 2002. We paid Barrington approximately $4.4 million in 2001.

        The additional information required by this item is set forth under Certain Relationships and Transactions and Compensation Committee Interlocks and Insider Participation in the Proxy Statement and is incorporated herein by reference.

94

PART IV

Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K

	(a) The following documents are filed as a part of this Report:
1.	Financial Statements:
	Report of Independent Accountants dated January 21, 2002 of PricewaterhouseCoopers LLP
	Consolidated Statements of Income—Constellation Energy Group for three years ended December 31, 2001
	Consolidated Statements of Comprehensive Income—Constellation Energy Group for three years ended December 31, 2001
	Consolidated Balance Sheets—Constellation Energy Group at December 31, 2001 and December 31, 2000
	Consolidated Statements of Cash Flows—Constellation Energy Group for three years ended December 31, 2001
	Consolidated Statements of Common Shareholders' Equity—Constellation Energy Group for three years ended December 31, 2001
	Consolidated Statements of Capitalization—Constellation Energy Group at December 31, 2001 and December 31, 2000
	Consolidated Statements of Income Taxes—Constellation Energy Group for three years ended December 31, 2001
	Consolidated Statements of Income—Baltimore Gas and Electric Company for three years ended December 31, 2001
	Consolidated Statements of Comprehensive Income—Baltimore Gas and Electric Company for three years ended December 31, 2001
	Consolidated Balance Sheets—Baltimore Gas and Electric Company at December 31, 2001 and December 31, 2000
	Consolidated Statements of Cash Flows—Baltimore Gas and Electric Company for three years ended December 31, 2001
	Notes to Consolidated Financial Statements
2.	Financial Statement Schedules:
	Schedule II—Valuation and Qualifying Accounts
	Schedules other than Schedule II are omitted as not applicable or not required.
3.	Exhibits Required by Item 601 of Regulation S-K.

Exhibit Number
*2		—	Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 in Form S-4 dated March 3, 1999, File No. 33-64799.)
*2	(a)	—	Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)
*2	(b)	—	Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)
*3	(a)	—	Articles of Amendment and Restatement of the Charter of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Exhibit No. 99.2 in Form 8-K dated April 30, 1999, File No. 1-1910.)
*3	(b)	—	Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999. (Designated as Exhibit No. 3(a) in Form 10-Q dated August 13, 1999, File Nos. 1-12869 and 1-1910.)
*3	(c)	—	Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999. (Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)
*3	(d)	—	Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 in Form 10-Q dated November 14, 1996, File No. 1-1910.)
3	(e)	—	Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 20, 2001.
3	(f)	—	Bylaws of Constellation Energy Group, Inc, as amended to February 25, 2002.

95

*3	(g)	—	Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 in Form 10-Q dated November 13, 1998, File No. 1-1910.)
*4	(a)	—	Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) in Form S-3 dated March 29,1999, File No. 333-75217.)
*4	(b)	—	Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910); and the following Supplemental Indentures between BGE and Bankers Trust Company, Trustee:

Dated	File No.	Designated In	Exhibit Number
*July 15, 1977	2-59772		2-3
(3 Indentures)
*August 15, 1991	33-45259	(Form S-3 Registration)	4(a)(i)
*January 15, 1992	33-45259	(Form S-3 Registration)	4(a)(ii)
*July 1, 1992	1-1910	(Form 8-K Report for January 29, 1993)	4(a)
*February 15, 1993	1-1910	(Form 10-K Annual Report for 1992)	4(a)(i)
*March 1, 1993	1-1910	(Form 10-K Annual Report for 1992)	4(a)(ii)
*March 15, 1993	1-1910	(Form 10-K Annual Report for 1992)	4(a)(iii)
*April 15, 1993	1-1910	(Form 10-Q dated May 13, 1993)	4
*July 1, 1993	1-1910	(Form 10-Q dated August 13, 1993)	4(a)
*October 15, 1993	1-1910	(Form 10-Q dated November 12, 1993)	4
*June 15, 1996	1-1910	(Form 10-Q dated August 13, 1996)	4

*4	(c)	—	Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
*4	(d)	—	Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures. (Designated as Exhibit 4(d) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4	(e)	—	Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures. (Designated as Exhibit 4(e) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4	(f)	—	Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4	(g)	—	Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4	(h)	—	Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4	(i)	—	Specimen Note for $173,000,000 6.75% Remarketable or Redeemable Securities (ROARSSM) due 2012 (Designated as Exhibit 4(f) in Form 8-K dated December 20, 2000, File No. 1-1910.)
10	(a)	—	Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated.
*10	(b)	—	Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 2000, File Nos. 1-12869 and 1-1910.)
10	(c)	—	Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated.

96

10	(d)	—	Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated.
*10	(e)	—	Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(m) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
*10	(f)	—	Summary of severance arrangement for Edward A. Crooke. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)
*10	(g)	—	Grantor Trust Agreement Dated as of January 1, 2001 between Constellation Energy Group, Inc. and Citibank, N.A. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 2000, File Nos. 1-12869 and 1-1910.)
10	(h)	—	Form of Severance Agreements between Constellation Energy Group, Inc. and the following named executive officers: Christian H. Poindexter, Mayo A. Shattuck, and Frank O. Heintz.
*10	(i)	—	Grantor Trust Agreement dated as of April 30, 1999 between Constellation Energy Group, Inc. and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(e) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
*10	(j)	—	Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 10-Q dated August 14, 2000, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
*10	(k)	—	Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 10-Q dated September 30, 2001, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
*10	(l)	—	Full Requirements Service Agreement between Baltimore Gas and Electric Company and Allegheny Energy Supply Company, L.L.C. (Designated as Exhibit No. 10(b) in Form 10-Q dated September 30, 2001, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
10	(m)	—	Constellation Energy Group, Inc. Benefits Restoration Plan, as amended and restated.
10	(n)	—	Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated.
10	(o)	—	Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated.
10	(p)	—	Constellation Energy Group, Inc. Supplemental Benefits Plan, as amended and restated.
10	(q)	—	Compensation agreements between Constellation Energy Group, Inc. and Michael J. Wallace (Attachment 1—Employment Agreement; Attachment 2—Severance Agreement.)
10	(r)	—	Compensation agreements between Constellation Energy Group, Inc. and Thomas V. Brooks (Attachment 1—Offer letter; Attachment 2—Equity letter; Attachment 3—Retention plan summary.)
10	(s)	—	Agreement, Release, and Waiver between Constellation Energy Group, Inc. and Eric P. Grubman.
12	(a)	—	Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.
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.
21		—	Subsidiaries of the Registrant.
23		—	Consent of PricewaterhouseCoopers LLP, Independent Accountants.

        * Incorporated by Reference.

(b)

Reports on Form 8-K:

Date Filed		Item Reported
Constellation Energy and BGE
	October 26, 2001	Item 5. Other Event Item 7. Financial Statements and Exhibits

97

CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
AND
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

Column A			Column B			Column C					Column D			Column E
						Additions
Description			Balance at beginning of period			Charged to costs and expenses		Charged to Other Accounts—Describe			(Deductions)—Describe			Balance at end of period
			(in millions)
Reserves deducted in the Balance Sheet from the assets to which they apply:
Constellation Energy
	Accumulated Provision for Uncollectibles
		2001	$	21.3		$	26.5	$	—		$	(25.0	)(A)	$	22.8
		2000		34.8			21.1		—			(34.6	)(A)		21.3
		1999		35.4			21.5		—			(22.1	)(A)		34.8
	Valuation Allowance—
		Net unrealized (gain) loss on available for sale securities
		2001		(33.7	)		—		(210.0	)(B)		—			(243.7	)
		2000		0.2			—		(33.9	)(B)		—			(33.7	)
		1999		(9.4	)		—		9.6	(B)		—			0.2
		Net unrealized (gain) loss on nuclear decommissioning trust funds
		2001		(34.7	)		—		13.7	(B)		—			(21.0	)
		2000		(40.5	)		—		5.8	(B)		—			(34.7	)
		1999		(23.9	)		—		(16.6	)(B)		—			(40.5	)
		Mark-to-market energy assets reserves
		2001		(54.4	)		—		11.0	(D)		—			(43.4	)
		2000		(27.5	)		—		(26.9	)(D)		—			(54.4	)
		1999		(0.6	)		—		(26.9	)(D)		—			(27.5	)
BGE
	Accumulated Provision for Uncollectibles
		2001		13.4			21.8		—			(21.8	)(A)		13.4
		2000		13.0			16.4		—			(16.0	)(A)		13.4
		1999		35.4			17.6		—			(40.0	)(E)		13.0
	Valuation Allowance—
		Net unrealized (gain) loss on available for sale securities
		2001		—			—		—			—			—
		2000		—			—		—			—			—
		1999		(9.4	)		—		(5.3	)(B)		14.7	(F)		—
		Net unrealized (gain) loss on nuclear decommissioning trust fund
		2001		—			—		—			—			—
		2000		(40.5	)		—		(1.8	)(C)		42.3	(G)		—
		1999		(23.9	)		—		(16.6	)(C)		—			(40.5	)

(A)

Represents principally net amounts charged off as uncollectible.

(B)

Represents net unrealized (gains)/losses (credited)/charged to accumulated other comprehensive income.

(C)

Represents net unrealized gains credited to accumulated depreciation.

(D)

Represents reserves from mark-to-market energy assets credited/(charged) to revenues.

(E)

Represents approximately $17 million charged off as uncollectible and approximately $23 million transferred from BGE to Constellation Energy as a result of the formation of the holding company.

(F)

Represents amount transferred from BGE to Constellation Energy as a result of the formation of the holding company.

(G)

Represents balance transferred to a subsidiary of Constellation Nuclear, LLC on July 1, 2000.

98

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Constellation Energy Group, Inc., the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

		CONSTELLATION ENERGY GROUP, INC. (Registrant)
Date: March 29, 2002	By	/s/	MAYO A. SHATTUCK III
		Mayo A. Shattuck III Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Constellation Energy Group, Inc., the Registrant, and in the capacities and on the dates indicated.

Signature			Title	Date
Principal executive officer and director:
By	/s/	M. A. Shattuck III	Chief Executive Officer, President and Director	March 29, 2002
	M. A. Shattuck, III
Principal financial and accounting officer:
By	/s/	E. F. Smith	Senior Vice President and Chief Financial Officer	March 29, 2002
	E. F. Smith
Directors:
/s/		D. L. Becker	Director	March 29, 2002
D. L. Becker
/s/		J. T. Brady	Director	March 29, 2002
J. T. Brady
/s/		F. P. Bramble, Sr.	Director	March 29, 2002
F. P. Bramble, Sr.
/s/		B. B. Byron	Director	March 29, 2002
B. B. Byron
/s/		E. A. Crooke	Director	March 29, 2002
E. A. Crooke
/s/		J. R. Curtiss	Director	March 29, 2002
J. R. Curtiss
/s/		R. W. Gale	Director	March 29, 2002
R. W. Gale

99

/s/	F. A. Hrabowski, III	Director	March 29, 2002
F. A. Hrabowski, III
/s/	E. J. Kelly, III	Director	March 29, 2002
E. J. Kelly, III
/s/	N. Lampton	Director	March 29, 2002
N. Lampton
/s/	C. R. Larson	Director	March 29, 2002
C. R. Larson
/s/	R. J. Lawless	Director	March 29, 2002
R. J. Lawless
/s/	C. H. Poindexter	Director	March 29, 2002
C. H. Poindexter
/s/	M. D. Sullivan	Director	March 29, 2002
M. D. Sullivan

100

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

	BALTIMORE GAS AND ELECTRIC COMPANY (Registrant)
Date: March 29, 2002	By	/s/	FRANK O. HEINTZ
		Frank O. Heintz President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company, the Registrant, and in the capacities and on the dates indicated.

Signature			Title	Date
Principal executive officer and director:
By	/s/	F. O. Heintz	President, Chief Executive Officer, and Director	March 29, 2002
	F. O. Heintz
Principal financial and accounting officer:
By	/s/	E. F. Smith	Senior Vice President and Chief Financial Officer	March 29, 2002
	E. F. Smith
Directors:
/s/		T. F. Brady	Director	March 29, 2002
T. F. Brady
/s/		D. A. Brune	Director	March 29, 2002
D. A. Brune
/s/		C. H. Poindexter	Director	March 29, 2002
C. H. Poindexter
/s/		M. A. Shattuck, III	Director	March 29, 2002
M. A. Shattuck, III

101

EXHIBIT INDEX

Exhibit Number
*2		—	Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 in Form S-4 dated March 3, 1999, File No. 33-64799.)
*2	(a)	—	Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)
*2	(b)	—	Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)
*3	(a)	—	Articles of Amendment and Restatement of the Charter of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Exhibit No. 99.2 in Form 8-K dated April 30, 1999, File No. 1-1910.)
*3	(b)	—	Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999. (Designated as Exhibit No. 3(a) in Form 10-Q dated August 13, 1999, File Nos. 1-12869 and 1-1910.)
*3	(c)	—	Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999. (Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)
*3	(d)	—	Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 in Form 10-Q dated November 14, 1996, File No. 1-1910.)
3	(e)	—	Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 20, 2001.
3	(f)	—	Bylaws of Constellation Energy Group, Inc, as amended to February 25, 2002.
*3	(g)	—	Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 in Form 10-Q dated November 13, 1998, File No. 1-1910.)
*4	(a)	—	Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) in Form S-3 dated March 29,1999, File No. 333-75217.)
*4	(b)	—	Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910); and the following Supplemental Indentures between BGE and Bankers Trust Company, Trustee:

Dated	File No.	Designated In	Exhibit Number
*July 15, 1977	2-59772		2-3
(3 Indentures)
*August 15, 1991	33-45259	(Form S-3 Registration)	4(a)(i)
*January 15, 1992	33-45259	(Form S-3 Registration)	4(a)(ii)
*July 1, 1992	1-1910	(Form 8-K Report for January 29, 1993)	4(a)
*February 15, 1993	1-1910	(Form 10-K Annual Report for 1992)	4(a)(i)
*March 1, 1993	1-1910	(Form 10-K Annual Report for 1992)	4(a)(ii)
*March 15, 1993	1-1910	(Form 10-K Annual Report for 1992)	4(a)(iii)
*April 15, 1993	1-1910	(Form 10-Q dated May 13, 1993)	4
*July 1, 1993	1-1910	(Form 10-Q dated August 13, 1993)	4(a)
*October 15, 1993	1-1910	(Form 10-Q dated November 12, 1993)	4
*June 15, 1996	1-1910	(Form 10-Q dated August 13, 1996)	4

*4
(c)
—
Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)

102

*4	(d)	—	Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures. (Designated as Exhibit 4(d) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4	(e)	—	Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures. (Designated as Exhibit 4(e) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4	(f)	—	Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4	(g)	—	Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4	(h)	—	Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4	(i)	—	Specimen Note for $173,000,000 6.75% Remarketable or Redeemable Securities (ROARSSM) due 2012 (Designated as Exhibit 4(f) in Form 8-K dated December 20, 2000, File No. 1-1910.)
10	(a)	—	Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated.
*10	(b)	—	Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 2000, File Nos. 1-12869 and 1-1910.)
10	(c)	—	Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated.
10	(d)	—	Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated.
*10	(e)	—	Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(m) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
*10	(f)	—	Summary of severance arrangement for Edward A. Crooke. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)
*10	(g)	—	Grantor Trust Agreement Dated as of January 1, 2001 between Constellation Energy Group, Inc. and Citibank, N.A. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 2000, File Nos. 1-12869 and 1-1910.)
10	(h)	—	Form of Severance Agreements between Constellation Energy Group, Inc. and the following named executive officers: Christian H. Poindexter, Mayo A. Shattuck, and Frank O. Heintz.
*10	(i)	—	Grantor Trust Agreement dated as of April 30, 1999 between Constellation Energy Group, Inc. and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(e) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
*10	(j)	—	Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 10-Q dated August 14, 2000, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
*10	(k)	—	Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 10-Q dated September 30, 2001, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
*10	(l)	—	Full Requirements Service Agreement between Baltimore Gas and Electric Company and Allegheny Energy Supply Company, L.L.C. (Designated as Exhibit No. 10(b) in Form 10-Q dated September 30, 2001, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
10	(m)	—	Constellation Energy Group, Inc. Benefits Restoration Plan, as amended and restated.
10	(n)	—	Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated.
10	(o)	—	Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated.

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10	(p)	—	Constellation Energy Group, Inc. Supplemental Benefits Plan, as amended and restated.
10	(q)	—	Compensation agreements between Constellation Energy Group, Inc. and Michael J. Wallace (Attachment 1—Employment Agreement; Attachment 2—Severance Agreement.)
10	(r)	—	Compensation agreements between Constellation Energy Group, Inc. and Thomas V. Brooks (Attachment 1—Offer letter; Attachment 2—Equity letter; Attachment 3—Retention plan summary.)
10	(s)	—	Agreement, Release, and Waiver between Constellation Energy Group, Inc. and Eric P. Grubman.
12	(a)	—	Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.
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.
21		—	Subsidiaries of the Registrant.
23		—	Consent of PricewaterhouseCoopers LLP, Independent Accountants.

        * Incorporated by Reference.

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EX-3.(E)

Exhibit 3(e)

CONSTELLATION ENERGY GROUP, INC.

ARTICLES SUPPLEMENTARY

                                Constellation Energy Group, Inc., a Maryland corporation (the “Corporation”), hereby certifies to the State Department of Assessments and Taxation of Maryland, that:

                                FIRST:  Under the power contained in Title 3, Subtitle 8 of the Maryland General Corporation Law (the “MGCL”), the Corporation, by resolutions duly adopted by its Board of Directors, has elected to become subject to Section 3-804 (b) and (c) of the MGCL.

                                SECOND:  The resolutions described above provide that, notwithstanding any other provision in the charter or the by-laws of the Corporation to the contrary, the Corporation elects to be subject to Section 3-804 (b) and (c) of the MGCL, the repeal of which may be effected only by the means authorized by Section 3-802(b)(3) of the MGCL.  Accordingly, pursuant to Section 3-804(b) the number of directors of the Corporation shall be fixed only by vote of the board of directors.  Pursuant to Section 3-804(c): (i) any vacancy on the board of directors of the Corporation may be filled only by the affirmative vote of a majority of the remaining directors in office, even if the remaining directors do not constitute a quorum; and (ii) any director elected to fill a vacancy shall hold office for the remainder of the full term of the class of directors in which the vacancy occurred, and until a successor is elected and qualified.

                                THIRD:  The election by the Corporation to be subject to Sections 3-804(b) and (c) as set forth in these Articles Supplementary has been approved by the Board of Directors of the Corporation in the manner and by the vote required by law.

                                FOURTH:  The undersigned Chairman of the Board of the Corporation acknowledges these Articles Supplementary to be the corporate act of the Corporation and, as to all matters or facts required to be verified under oath, the undersigned Chairman of the Board acknowledges that, to the best of his knowledge, information and belief, these matters and facts are true in all material respects and that this statement is made under the penalties for perjury.

                                IN WITNESS WHEREOF, the Corporation has caused these Articles Supplementary to be executed under seal in its name and on its behalf by its Chairman of the Board and attested by its Vice President and Secretary on this 20th day of November, 2001.

ATTEST:                                                                               CONSTELLATION ENERGY

                                                                                                GROUP, INC.

By: David A. Brune                                                             By: Christian H. Poindexter (SEAL)

       Vice President and Secretary                                             Chairman of The Board

EX-3.(F)

BY-LAWS

of

CONSTELLATION ENERGY GROUP, INC.

Amended as of February 25, 2002

ARTICLE I

OFFICES AND HEADQUARTERS

Section 1. - Name.

The name of the corporation is Constellation Energy Group, Inc. (the “Corporation”).

Section 2. - Offices.

The principal office of the Corporation is 250 West Pratt Street, Baltimore, Maryland 21201. The Corporation may also have other offices at such other places, either within or without the State of Maryland, as the Board of Directors of the Corporation (the “Board”) may determine or as the activities of the Corporation may require.

ARTICLE II

STOCKHOLDERS

Section 1. - Place of Meetings.

Meetings of stockholders of the Corporation shall be held at such places, either within or without the State of Maryland as may be fixed from time to time by the Board and stated in the notice of meeting or in a duly executed waiver of notice thereof.

Section 2. - Annual Meetings.

The Annual Meeting of the stockholders for the election of Directors and for the transaction of general business shall be held on any date during the period of May 1 through May 31, as determined year to year by the Board.  The time and location of the meeting shall be determined by the Board.  Failure to hold an Annual Meeting does not invalidate the Corporation’s existence or affect any otherwise valid corporate acts.

The Chief Executive Officer of the Corporation shall prepare, or cause to be prepared, an annual report containing a full and correct statement of the affairs of the Corporation, including a balance sheet and a financial statement of operations for the preceding fiscal year, which shall be submitted to the stockholders at or prior to the Annual Meeting.

Section 3. - Special Meetings.

Special meetings of the stockholders may be held in the City of Baltimore or in any county in which the Corporation provides service or owns property upon call by the Chairman of the Board, President or a majority of the Board whenever they deem expedient, or by the Secretary upon the written request of the holders of shares entitled to not less than a majority of all the votes entitled to be cast at such meeting.  Such request of the stockholders shall state the purpose or purposes of the meeting and the matters proposed to be acted on thereat and shall be delivered to the Secretary, who shall inform such stockholders of the reasonably estimated cost of preparing and mailing such notice of the meeting, and upon payment to the Corporation of such costs the Secretary shall give notice stating the purpose or purposes of the meeting to all stockholders entitled to vote at such meeting.  The business at all special meetings shall be confined to that specifically named in the notice thereof.

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Section 4. - Notice and Waiver; Organization of Meeting.

When stockholders are required or permitted to take any action at a meeting whether special or annual, written or printed notice of every meeting shall be given to each stockholder entitled to vote at the meeting and each other stockholder entitled to notice of the meeting.  The notice shall state the place, day, and hour of such meeting and, in the case of a special meeting, the purpose or purposes for which the meeting is called.  The written notice of any meeting shall be given, personally or by mail, not less than 10 or more than 90 days before the date of the meeting.  If mailed, such notice shall be deemed given when deposited with the United States Postal Service, postage prepaid, addressed to the stockholder at his or her address as it appears on the records of the Corporation or its registrar.  The business at all special meetings shall be confined to that specifically named in the notice thereof.

When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting if the time and place thereof are announced at the meeting at which the adjournment is taken unless the adjournment is for more than 120 days, or, if after the adjournment, a new record date is fixed for the adjourned meeting, in which circumstances a notice of the adjourned meeting shall be given to each stockholder of record entitled to vote at the meeting.  At the adjourned meeting the Corporation may transact any business which might have been transacted at the original meeting.

Notice of any meeting of stockholders may be waived in writing by any stockholders entitled to vote at such meeting.  Attendance at a meeting by any stockholder, in person or by proxy, shall constitute a waiver of notice of such meeting, except when the person attends a meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened.

All meetings of the stockholders shall be called to order by the Chairman of the Board, or in his or her absence by the President or a Vice President; or in the case of the absence of such Officers, then by any stockholder.  The party calling the meeting to order shall be Chairman of the meeting.  The Secretary of the Corporation, if present, shall act as secretary of the meeting, unless some other person shall be elected by the stockholders at the meeting to act as secretary.  An accurate record of the meeting shall be kept by the secretary thereof, and placed in the record books of the Corporation.

Section 5. - Order of Business.

(a)At any Annual Meeting, only such business shall be conducted as shall have been brought before the Annual Meeting (i) by or at the direction of the Board, or (ii) by any stockholder who complies with the procedures set forth in this Section 5.

(b)For nominations or other business to be brought properly before an Annual Meeting by a stockholder, the stockholder must have given timely notice thereof in proper written form to the Secretary of the Corporation.  To be timely, a stockholder’s notice must be delivered to or mailed and received at the principal office of the Corporation not less than 75 days prior to the anniversary of the date on which notice of the prior year’s Annual Meeting was given to stockholders in accordance with Section 4 of this Article II.  Notices by facsimile or electronically will not be accepted by the Secretary of the Corporation.  To be in proper written form, a stockholder’s notice to the Secretary shall set forth in writing as to each matter the stockholder proposes to bring before the Annual Meeting:

(i)as to each person whom the stockholder proposes to nominate for election or re-election as a Director, all information relating to such person that is required to be disclosed in solicitations of proxies for election of Directors, or is otherwise required, in each case pursuant to Regulation 14A under the Securities Exchange Act of 1934 (the “Exchange Act”) or any applicable successor

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provisions thereto, including such person’s written consent to being named in the proxy statement as a nominee and to serving as a Director if elected; and as to the stockholder giving the notice, the name and address, as they appear on the Corporation’s books, of the stockholder proposing such nomination and the class and number of shares of stock of the Corporation which are beneficially owned by the stockholder.

(ii)as to any other business that the stockholder proposes to bring before the meeting:

(A)a brief description of the business desired to be brought before the Annual Meeting and the reasons for conducting such business at the Annual Meeting;

(B)the name and address, as they appear on the Corporation’s books, of the stockholder proposing such business;

(C)the class and number of shares of stock of the Corporation which are beneficially owned by the stockholder; and

(D)any material interest of the stockholder in such business.

(c)Notwithstanding anything in these by-laws to the contrary, no business shall be conducted at an Annual Meeting except in accordance with the procedures set forth in this Section 5 of Article II.  The Chairman of an Annual Meeting shall, if the facts warrant, determine and declare at the Annual Meeting that business was not properly brought before the Annual Meeting in accordance with the provisions of this Section 5 of Article II and, if the Chairman should so determine, he or she shall so declare at the Annual Meeting and any such business not properly brought before the Annual Meeting shall not be transacted.

(d)Notwithstanding the foregoing provisions of this Section, a stockholder shall also comply with all applicable requirements of the Exchange Act and the rules and regulations thereunder with respect to the matters set forth in this Section.  Nothing in this Section shall be deemed to affect any rights of stockholders to request inclusion of proposals in the Corporation’s proxy statement pursuant to Rule 14a-8 under the Exchange Act.

Section 6. - Quorum.

At any meeting of the stockholders the presence in person or by proxy of stockholders entitled to cast a majority of the votes thereat shall constitute a quorum for the transaction of business.

When a quorum is once present to organize a meeting, it is not broken by the subsequent withdrawal of any stockholders.

The stockholders present, although less than a quorum, may adjourn the meeting to another time or place; provided that notice of such adjourned meeting is given in accordance with the provisions of Section 4 of this Article II.

Section 7. - Voting; Proxies.

At all meetings of the stockholders each stockholder shall be entitled to one vote for each share of Common Stock standing in his or her name and, when the Preferred Stock is entitled to vote, such number of votes as shall be provided in the Charter of the Corporation for each share of Preferred Stock standing in his or her name, and the votes shall be cast by stockholders in person or by lawful proxy.  However, no proxy shall be voted 11 months after the date thereof, unless the proxy provides for a longer period.

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Section 8. -  Control Shares.

Notwithstanding any other provision of the Charter of the Corporation or these by-laws, Title 3, Subtitle 7 of the Maryland General Corporation Law (or any successor statute) shall not apply to any acquisition by any person of shares of stock of the Corporation.  This section may be repealed, in whole or in part, at any time, whether before or after an acquisition of control shares and, upon such repeal, may, to the extent provided by any successor by-law, apply to any prior or subsequent control share acquisition.

Section 9. - Method of Voting.

All elections and all other questions shall be decided by a majority of the votes cast, at a meeting at which a quorum is present, except as expressly provided otherwise by the general laws of the State of Maryland or the Charter and except that Directors shall be elected by a plurality of the votes cast.

Section 10. - Ownership of its Own Stock.

Shares of capital stock of the Corporation held by either (i) the Corporation or (ii) another corporation, if a majority of the shares entitled to vote in the election of Directors of such other corporation is held, directly or indirectly, by the Corporation (a “Controlled Corporation”), shall neither be entitled to vote nor be counted for quorum purposes.  Nothing in this Section 10 shall be construed as limiting the right of the Corporation or any Controlled Corporation to vote stock of the Corporation held by it in a fiduciary capacity.

Section 11. - Inspectors.

The Board of Directors, in advance of any meeting, may, but need not, appoint one or more individual inspectors or one or more entities that designate individuals as inspectors to act at the meeting or any adjournment thereof.  If an inspector or inspectors are not appointed, the person presiding at the meeting may, but need not, appoint one or more inspectors.  In case any person who may be appointed as an inspector fails to appear or act, the vacancy may be filled by appointment made by the Board of Directors in advance of the meeting or at the meeting by the chairman of the meeting.  The inspectors, if any, shall determine the number of shares outstanding and the voting power of each, the shares represented at the meeting, the existence of a quorum, the validity and effect of proxies, and shall receive votes, ballots or consents, hear and determine all challenges and questions arising in connection with the right to vote, count and tabulate all votes, ballots or consents, determine the result, and do such acts as are proper to conduct the election or vote with fairness to all stockholders.  Each such report shall be in writing and signed by him or her or by a majority of them if there is more than one inspector acting at such meeting.  If there is more than one inspector, the report of a majority shall be the report of the inspectors.  The report of the inspector or inspectors on the number of shares represented at the meeting and the results of the voting shall be prima facie evidence thereof.

Section 12. - Record Date for Stockholders; Closing of Transfer Books.

The Board may fix, in advance, a date as the record for the determination of the stockholders entitled to notice of, or to vote at, any meeting of stockholders, or entitled to receive payment of any dividend, or entitled to the allotment of any rights, or for any other proper purpose.  Such date in any case shall not be more than 90 days (and in the case of a meeting of stockholders not less than 10 days) prior to the date on which the particular action requiring such determination of stockholders is to be taken.  Only stockholders of record on such date shall be entitled to notice of or to vote at such meeting or to receive such dividends or rights, as the case may be.  In lieu of fixing a record date the Board may close the stock transfer books of the Corporation for a period not exceeding 20 nor less than 10 days preceding the date of any meeting of stockholders or not exceeding 20 days preceding any other of the above mentioned events.

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ARTICLE III

BOARD OF DIRECTORS AND COMMITTEES

Section 1. - Powers of Directors

The business and affairs of the Corporation shall be managed under the direction of the Board which shall have and may exercise all the powers of the Corporation, except such as are expressly conferred upon or reserved by the stockholders by law, by Charter, or by these by-laws.  Except as otherwise provided herein, the Board shall appoint the Officers for the conduct of the business of the Corporation, determine their duties and responsibilities.  The Board may remove any Officer.

Section 2. - Number and Election of Directors.

The number of Directors shall be fifteen (15) or such number as shall be fixed only by vote of the Directors.  The Directors shall be grouped into three classes, Class I, Class II and Class III.  Directors in each class shall serve a term of three years and until their successors are elected and qualified, or until their earlier resignation or removal.  A separate class will be elected at each Annual Meeting of the stockholders.

Section 3. - Vacancies.

If for any reason any or all the Directors cease to be Directors, such event shall not terminate the Corporation or affect these by-laws or the powers of the remaining Directors hereunder (even if fewer than three Directors remain).  Except as may be provided by the Board in setting the terms of any class or series of preferred stock, any vacancy on the Board may be filled only by a majority of the remaining Directors, even if the remaining Directors do not constitute a quorum.  Any Director elected to fill a vacancy shall serve for the remainder of the full term of the class in which the vacancy occurred and until a successor is elected and qualified.

Section 4. - Resignations.

Any Director of the Corporation may resign at any time by giving written notice to the Corporation.  Such resignation shall take effect at the time specified therein, if any, or if no time is specified therein, then upon receipt of such notice by the Corporation; and, unless otherwise provided therein, the acceptance of such resignation shall not be necessary to make it effective.

Section 5. - Meetings of the Board.

A regular meeting of the Board shall be held immediately after the Annual Meeting of stockholders or any special meeting of the stockholders at which the Board is elected, and thereafter regular meetings of the Board shall be held on such dates during the year as may be designated from time to time by the Board.  All meetings of the Board shall be held at the general offices of the Corporation in the City of Baltimore or elsewhere, as ordered by the Board.  Of all such meetings (except the regular meeting held immediately after the election of Directors) the Secretary shall give notice to each Director personally or by telephone, facsimile or electronically directed to, or by written notice deposited in the mails addressed to, his or her residence or business address at least 48 hours before such meeting.

Special meetings may be held at any time or place upon the call of the Chairman of the Board, or the President, or in their absence, on order of the Executive Committee by notices as above.  In the event all of the Directors in office waive notice of any meeting in writing at or before the meeting, the meeting may be held without the aforesaid advance notices.

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The Chairman shall preside at all meetings of the Board, or, in his or her absence, the President or one of the Vice Presidents (if a member of the Board) shall preside.  If at any meeting none of the foregoing persons is present, the Directors present shall designate one of their number to preside at such meeting.

Section 6. - Telephone Meetings Permitted.

Members of the Board, or any committee, may participate in a meeting thereof by means of conference telephone or similar communications equipment in which all persons participating in the meeting can hear each other, and such participation shall constitute presence in person at such meeting.

Section 7. - Quorum.

A majority of the Directors in office shall constitute a quorum of the Board for the transaction of business.  If a quorum be not present at any meeting, a majority of the Directors present may adjourn to any time and place they may see fit.

Section 8. - Executive Committee.

The Directors shall annually, at their first meeting succeeding the stockholders’ meeting at which they are elected, elect from among their number an Executive Committee of at least three.  The Executive Committee may exercise, in the intervals between meetings of the Board, all of the powers of the Board in the management of the business and affairs of the Corporation, except the power to declare dividends, to issue stock other than as hereinafter stated, to recommend to stockholders any action requiring stockholder approval, amend the by-laws, or approve any merger or share exchange which does not require stockholder approval.  If the Board has given general authorization for the issuance of stock, the Executive Committee, in accordance with a general formula or method specified by the Board by resolution or by adoption of a stock option or other plan, may fix the terms of stock subject to classification or reclassification and the terms on which any stock may be issued, including all terms and conditions required or permitted to be established or authorized by the Board.

The members of the Executive Committee shall hold their offices as such for one year and until their successors are elected and qualified, or until their earlier resignation or removal. All vacancies in said Committee shall be filled by the Board, but in the absence of a member or members of the Executive Committee, the members thereof present at any meeting (whether or not they constitute a quorum) may appoint a member of the Board to act in the place of such absent member.  They shall designate one of their number as Chairman of the Committee, and shall keep a separate book of minutes of their proceedings and actions.  They shall elect a Secretary to the Committee who shall give notice personally or by mail, telephone, facsimile or electronically to each member of the Committee of all meetings, not later than 12 noon of the day before the meeting, unless all of the members of the Executive Committee in office waive notice thereof in writing at or before the meeting in which case the meeting may be held without the aforesaid advance notice.  Meetings may be called by the Chairman of the Committee or by the Chief Executive Officer, or, in the event of their absence, by one of the other Officers among the Chairman of the Board, the President or the Vice Presidents (if a member of the Board).  A majority of the members of the Executive Committee shall constitute a quorum for the transaction of business.

Section 9. - Audit Committee.

The Directors shall annually, at their first meeting succeeding the stockholders’ meeting at which they are elected, elect from among their number an Audit Committee which shall consist of at least three Directors who shall be independent of Management and free from any relationship that, in the opinion of the Board, would interfere with the exercise of independent judgment as a Committee member, provided that no Director who

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was formerly an Officer of the Corporation shall be a member of the said Audit Committee.  The members of the Audit Committee shall hold their offices as such for one year and until their successors are elected and qualified, or until their earlier resignation or removal.  All vacancies in said Committee shall be filled by the Board.  They shall designate one of their number as Chairman of the Committee, and shall keep a separate book of minutes of their proceedings and actions.  They shall elect a Secretary to the Committee who shall give notice personally or by mail, telephone, facsimile or electronically to each member of the Committee of all meetings, not later than 12 noon of the day before the meeting, unless all of the members of the Audit Committee in office waive notice thereof in writing at or before the meeting in which case the meeting may be held without the aforesaid advance notice.  A majority of the members of the Audit Committee shall constitute a quorum for the transaction of business.

The Audit Committee shall have the powers and duties set forth in the charter for the Audit Committee as adopted and amended from time to time by the Board of Directors in accordance with the applicable rules and regulations of the New York Stock Exchange, Inc. (and any other exchange on which the Corporation’s securities may be listed) and the United States Securities and Exchange Commission, as in effect from time to time.

Section 10. - Committee On Management.

The Directors shall annually, at their first meeting succeeding the stockholders’ meeting at which they are elected, elect from among their number a Committee on Management consisting of at least three members.  The members of the Committee on Management shall hold their offices as such for one year and until their successors are elected and qualified, or until their earlier resignation or removal.  All vacancies in said Committee shall be filled by the Board.  They shall designate one of their number as Chairman of the Committee, and shall keep a separate book of minutes of their proceedings and actions.  They shall elect a Secretary to the Committee who shall give notice personally or by mail, telephone, facsimile or electronically to each member of the Committee of all meetings, not later than 12 noon of the day before the meeting, unless all the members of the Committee on Management in office waive notice thereof in writing at or before the meeting in which case the meeting may be held without the aforesaid advance notice.  A majority of the members of the Committee on Management shall constitute a quorum for the transaction of business.

The Committee on Management shall recommend to the Board nominees for election as Directors and shall consider the performance of incumbent Directors in determining whether to nominate them to stand for reelection.  The Committee shall, among other things, consider any major changes in the internal organization of the Corporation.  It shall establish the remuneration arrangements for the Directors and for the Chairman of the Board, President, Chief Executive Officer and Officers reporting directly to the Chief Executive Officer.  The Committee shall recommend to the full Board nominees for Officers of the Corporation.  The Committee on Management shall have such additional powers and perform such duties as shall be prescribed by resolution of the Board.

Section 11. - Other Committees.

The Board is authorized to appoint from among its members such other committees as it may, from time to time, deem advisable and to delegate to such committee or committees any of the powers of the Board that it may lawfully delegate.  Each such committee shall consist of at least three Directors.

Section 12. - Fees and Expenses.

Each member of the Board, other than salaried Officers and employees, shall be paid an annual retainer fee, payable in such amount as shall be specified from time to time by the Board.  Each Committee Chair shall be paid an annual retainer fee, payable in  such amount as shall be specified from time to time by the Board.

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Each member of the Board, other than salaried Officers and employees, shall be paid such fee as shall be specified from time to time by the Board for attending each regular or special meeting of the Board and for attending, as a committee member, each meeting of the Executive Committee, Audit Committee, Committee on Management and any other committee appointed by the Board.  Each member shall be paid reasonable traveling expenses incident to attendance at meetings.

ARTICLE IV

OFFICERS

Section 1. - Officers.

The Corporation shall have a Chairman of the Board, a President, one or more Vice Presidents, a Treasurer, and a Secretary who shall be elected by, and hold office at the will of, the Board.  The Chairman of the Board shall be chosen from among the Directors.  The Board shall designate either the Chairman of the Board or the President to be the Chief Executive Officer of the Corporation.  The Board shall also elect such other Officers as they may deem necessary for the conduct of the business and affairs of the Corporation.  Any two offices, except those of President and Vice President, may be held by the same person, but no person shall sign checks, drafts and promissory notes, or execute, acknowledge or verify any other instrument in more than one capacity, if such instrument is required by law, the Charter, these by-laws, a resolution of the Board or order of the Chief Executive Officer to be signed, executed, acknowledged or verified by two or more Officers.  The President, any Vice President, or such other persons as may be designated by the Board, shall sign all special contracts of the Corporation, countersign checks, drafts and promissory notes, and such other papers as may be directed by the Board.  The President, or any Vice President, together with the Treasurer or an Assistant Treasurer (if any), shall have authority to sell, assign or transfer and deliver any bonds, stocks or other securities owned by the Corporation.  The Chairman of the Board, Chief Executive Officer, President and Officers reporting directly to the Chief Executive Officer shall receive such compensation as shall be fixed by the Committee on Management.  Compensation for all other Officers shall be fixed by the Chief Executive Officer.  The Board shall require a fidelity bond to be given by each Officer, or, in its discretion, the Board may substitute a general blanket fidelity bond or insurance contract to cover all Officers and employees.

Section 2. - Duties of the Officers.

(a)Chairman of the Board

The Chairman of the Board shall preside at all meetings of the Board and of stockholders.  The Chairman of the Board shall also have such other powers and duties as from time to time may be assigned by the Board.

(b)President

The President shall have general executive powers, as well as specific powers conferred by these by-laws. The President shall also have such other powers and duties as from time to time may be assigned by the Board.  In the absence of the Chairman of the Board, the President shall perform all the duties of the Chairman of the Board.

(c)Vice Presidents

Each Vice President shall have such powers and duties as may be assigned by the Board or the Chief Executive Officer, as well as the specific powers assigned by these by-laws. 

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A Vice President may be designated by the Board or the Chief Executive Officer to perform, in the absence of the President, all the duties of the President.

(d)Treasurer

The Treasurer shall have the care and the custody of the funds and valuable papers of the Corporation, and shall receive and disburse all moneys in such a manner as may be prescribed by the Board or the Chief Executive Officer.  The Treasurer shall have such other powers and duties as may be assigned by the Board, or the Chief Executive Officer, as well as specific powers assigned by these by-laws.

(e)Secretary

The Secretary shall attend all meetings of the stockholders and Directors and shall notify the stockholders and Directors of such meetings in the manner provided in these by-laws.  The Secretary shall record the proceedings of all such meetings in books kept for that purpose.  The Secretary shall have such other powers and duties as may be assigned by the Board or the Chief Executive Officer, as well as the specific powers assigned by these by-laws.

(f)Other Officers

Such other Officers as are appointed by the Board shall exercise such duties and have such powers as by custom and applicable law generally pertain to their respective offices as well as such duties and powers as the Board or the Chief Executive Officer may assign.

Section 3. - Terms of Office; Removals and Vacancies.

Any Officer may be removed by the Board in its sole judgment.  In case of removal, the salary of such Officer shall cease.  Removal shall be without prejudice to the contractual rights, if any, of the person so removed, but election of an Officer shall not of itself create contractual rights.

Each Officer shall hold office until his or her successor is elected and qualified or until his or her earlier removal or resignation.

Any vacancy occurring in any office of the Corporation shall be filled by the Board and the Officer so elected shall hold office for the unexpired term in respect of which the vacancy occurred and until his or her successor shall be duly elected and qualified.

In any event of absence or temporary disability of any Officer of the Corporation, the Board may authorize another person to perform the duties of that office.

Section 4. - Voting Securities Owned by the Corporation.

Powers of attorney, proxies, waivers of notice of meeting, consents and other instruments relating to securities owned by the Corporation may be executed in the name of and on behalf of the Corporation by the Chairman, the President or any Vice President and any such Officer may, in the name of and on behalf of the Corporation, take all such action as any such Officer may deem advisable to vote in person or by proxy at any meeting of security holders of any corporation in which the Corporation may own securities and at any such meeting shall possess and may exercise any and all rights and powers incident to the ownership of such securities and which, as the owner thereof, the Corporation might have exercised and possessed if present.  The Board may, by resolution, from time to time confer like powers upon any other person or persons.

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ARTICLE V

INDEMNIFICATION OF DIRECTORS AND OFFICERS

Section 1. - Procedure.

The Corporation shall indemnify all Directors, Officers and employees to the fullest extent permitted by the general laws of the State of Maryland and shall provide indemnification expenses in advance to the extent permitted thereby.  The Corporation will follow the procedures required by applicable law in determining persons eligible for indemnification and in making indemnification payments and advances.

Section 2. - Exclusivity, etc.

The indemnification and advance of expenses provided by the Charter and these by-laws shall not be deemed exclusive of any other rights to which a person seeking indemnification or advance of expenses may be entitled under any law (common or statutory), or any agreement, vote of stockholders or disinterested Directors or other provision that is consistent with law, both as to action in his or her official capacity and as to action in another capacity while holding office or while employed or acting as agent for the corporation, shall continue in respect of all events occurring while a person was a Director or Officer after such person has ceased to be a Director or Officer, and shall inure to the benefits of the estate, heirs, executors and administrators of such person.  All rights to indemnification and advance of expenses under the Charter of the Corporation and hereunder shall be deemed to be a contract between the Corporation and each Director or Officer of the Corporation who serves or served in such capacity at any time while this by-law is in effect. Nothing herein shall prevent the amendment of this by-law, provided that no such amendment shall diminish the rights of any person hereunder with respect to events occurring or claims made before its adoption or as to claims made after its adoption in respect of events occurring before its adoption.  Any repeal or modification of this by-law shall not in any way diminish any rights to indemnification or advance of expenses of such Director or Officer or the obligations of the Corporation arising hereunder with respect to events occurring, or claims made, while this by-law or any provision hereof is in force.

Section 3. - Severability; Definitions.

The invalidity or unenforceability of any provision of this Article V shall not affect the validity or enforceability  of any other provision hereof.  The phrase “this by-law” in this Article V means this Article V in its entirety.

ARTICLE VI

CAPITAL  STOCK

Section 1. - Evidence of Stock Ownership.

Evidence of ownership of stock in the Corporation may be either pursuant to a certificate(s) or a statement in compliance with the general laws of the State of Maryland, each of which shall represent the number of shares of stock owned by a stockholder in the Corporation.  Stockholders may request that their stock ownership be represented by a certificate(s).  In case any Officer who signed any certificate, in facsimile or otherwise, ceases to be such Officer of the Corporation before the certificate is issued, the certificate may nevertheless be issued by the Corporation with the same effect as if the Officer had not ceased to be such Officer as of the date of its issue.

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For stock ownership evidenced by a statement, such statement shall be in such form, and executed, as required from time to time by the general laws of the State of Maryland.

Section 2. - Transfer of Shares.

Stock shall be transferable only on the books of the Corporation by assignment in writing by the registered holder thereof, his or her legally constituted attorney, or his or her legal representative, either upon surrender and cancellation of the certificate(s) therefor, if such stock is represented by a certificate, or upon receipt of such other documentation for stock not represented by a certificate as the Board and the general laws of the State of Maryland may, from time to time, require.

Section 3. - Lost, Stolen or Destroyed Certificates.

No certificate for shares of stock of the Corporation shall be issued in place of any other certificate alleged to have been lost, stolen, or destroyed, except upon production of such evidence of the loss, theft or destruction and upon indemnification of the Corporation to such extent and in such manner as the Board may prescribe.

Section 4. - Transfer Agents and Registrars.

The Board shall appoint a person or persons, the Corporation or any incorporated trust company or companies or any of them, as transfer agents and registrars and, if stock is represented by a certificate, may require that such certificate bear the signatures or the counter-signatures of such transfer agents and registrars, or either of them.

Section 5. - Stock Ledger.

The Corporation shall maintain at its principal office, a stock record containing the names and addresses of all stockholders and the numbers of shares of each class held by each stockholder.

ARTICLE VII

MISCELLANEOUS

Section 1. - Seal.

The Board shall provide, subject to change, a suitable corporate seal which may be used by causing it, or facsimile thereof, to be impressed or affixed or reproduced on the Corporation’s stock certificates, bonds, or any other documents on which the seal may be appropriate.

Section 2. - Amendments.

These by-laws, or any of them, may be amended or repealed, and new by-laws may be made or adopted only at any meeting of the Board, by vote of a majority of the Directors or at a meeting of the shareholders, duly called, by a vote of two-thirds of the shareholders eligible to vote thereon.  Pursuant to Articles Supplementary filed with the State Department of Assessments and Taxation of Maryland, the Corporation has elected, by resolution of the Board, to be subject to Sections 3-803, 3-804(b), 3-804(c) and 3-805 of the Maryland General Corporation Law and the following sections of these by-laws have been amended to conform to such elections, respectively: Article III, Section 2, third, fourth and last sentences; Article III, Section 2, first sentence; Article III, Section 3; and Article II, Section 3, first sentence, and therefore, such provisions may be amended, altered or repealed only by resolution of the Board.

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Section 3. - Section Headings and Statutory References.

The headings of the Articles and Sections of these by-laws have been inserted for convenience of reference only and shall not be deemed to be a part of these by-laws.

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EX-10.(A)

Exhibit 10(a)

Executive Annual Incentive Plan

Of

Constellation Energy Group, Inc.

1.Plan Objective.  The objective of this Plan is to allow Constellation Energy Group, Inc. (Constellation Energy Group or Company) to attract, retain and motivate highly competent officers and key employees of the Company and its subsidiaries by focusing incentive compensation toward the achievement of performance results that primarily support the interests of shareholders and customers of the Company.

2.Plan Administration.  The Plan is administered by the Constellation Energy Group Board of Directors’ (Board) Committee on Management (Committee on Management) which has sole authority (unless otherwise specified herein) to interpret the Plan; to refine its provisions from time to time, particularly those relating to factors, targets and procedures used in connection with calculating the awards (which refinements shall be reflected in guidelines for the performance year); to suspend the Plan at any time; and in general, to make all other determinations necessary or advisable for the administration of the Plan to achieve its stated objective.

The Committee on Management shall have the power to delegate all or any part of their duties to one or more designees, and to withdraw such authority, by written designation.

3.Eligibility.  Each officer or key employee of Constellation Energy Group or its subsidiaries may be designated in writing by the Committee on Management as a participant under the Plan.  Once designated, participation shall continue until such designation is withdrawn at the discretion and by written order of the Committee on Management.  Participation is subject to the following conditions:

Participant must have been an eligible participant for some portion of the performance year and at the time of distribution be actively employed by the Company or elsewhere with the approval of the Company unless employment was terminated by death, disability or retirement.  Except as otherwise provided herein, where an individual is not an eligible participant for the entire performance year, the amount of the award, whether full, partial or none, will be at the Committee on Management’s discretion.

Where, prior to the end of a performance year, a participant’s active employment is terminated as a result of death, disability or retirement, the award is calculated based on the participant’s position at the time of termination.  Unless otherwise stated, any such award will be made on a pro-rata basis for the period of active employment, or, in total, at the discretion of the Committee on Management.  Where active employment is terminated as a result of death of participant, distribution is made in accordance with Section 9.  (Designation of Beneficiary) of this Plan.

4.Performance Goals

A.Performance Targets.  The Committee on Management shall establish for each plan year Performance Targets designed to accomplish the purpose set forth in Section 1 of this Plan.  The Committee on Management will ensure that each plan year’s Performance Targets meet the following general criteria:

(1)The interests of the Company’s shareholders will be balanced with the interests of the Company’s customers.

(2)           The targets should be set at levels which are attainable, but which, in the Committee on Management’s judgment, are attainable only with a high degree of competence and diligence.

The Committee on Management shall have sole authority to amend Performance Targets at any time when, in the Committee’s judgment, unforeseen circumstances exist which require modification in order to ensure that the purpose of the Plan is properly served.

The Committee on Management shall have authority to establish appropriate Performance Targets, differing to the degree necessary from those established for the Company, for each of the Company’s subsidiaries employing one or more participants in this Plan; and shall have authority to adjust such targets subsequently should unforeseen circumstances arise.

B.Individual Performance.  A participant’s individual per- formance will be evaluated by the Chairman of the Board.

5.Award Opportunity.  The Committee on Management shall establish for each plan year the Award Opportunity (minimum, target,

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and maximum, as appropriate) applicable to participants in the Plan.  The Award Opportunity may be allocated among the various Performance Targets and Individual Performance and may vary among classes of participants.

6.Award Determination.  The Committee on Management shall determine the Awards, if any, to be made for each plan year as soon after the end of the plan year as is practical.

Awards are calculated taking into account the degree of attainment of performance targets, individual performance, and the percent of participation during the performance year.  The dollar amount of the participants’ award is determined by multiplying the participant’s prior December 31 annualized base salary by the award percentage.

7.Payment of Awards.  Awards approved by the Committee on Management for each plan year shall be paid as soon as practicable after such determination has been made.  Payment may be made in a lump cash sum or, at the participants’ election, may be deferred in whole or in part.  When required by applicable law, Federal, State and FICA taxes will be withheld from awards at applicable rates.

Awards will not be paid for any performance year in which Company earnings are less than the amount necessary to fund the annual dividend.  Additionally, awards will not be paid for any plan year in which the dividend is suspended or effectively reduced from its prior amount.

8.Deferred Payment of Award.  A participant may elect to defer the receipt of all or a portion of the award for the plan 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 Constellation Energy Group Nonqualified Deferred Compensation Plan.

9.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 incentive compensation award to the extent a participant has chosen not to defer all or a portion of his incentive award pursuant to Section 8 hereof, should the participant die during the plan year and be entitled to an incentive award for that plan year.  Such designation shall apply only to the portion of the undistributed incentive 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 Vice President — Human Resources of the Company a notice on an appropriate form designated

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by the Vice President — Human Resourcesof the Company.  The last designation of beneficiary received by the Vice President — Human Resources of the Company 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 death of the participant.  Distribution of any incentive awards previously deferred pursuant to Section 8 of the Plan shall be paid to the beneficiary or beneficiaries designated under the Constellation Energy Group Nonqualified Deferred Compensation Plan.

10.Change in Control.  Notwithstanding any other provisions of this Plan to the contrary, if a participant separates from service with Constellation Energy Group or a subsidiary of Constellation Energy Group (except due to a participant’s transfer of employment to or from a subsidiary of Constellation Energy Group), within 2 years following a change in control, such participant is eligible for an award for the performance year during which the separation from service occurs.  The award is calculated assuming maximum performance achievement and based on the participant’s position at the time of termination and is pro-rated for the period of active employment during the performance year.  The Committee on Management, in its discretion, may grant a total, rather than pro-rated award.  Payment of the award will be made in a lump cash sum within 60 days after the participant’s separation from service.  Payment may not be deferred.

A change in control for purposes of this Section 10 shall mean (i) the purchase or acquisition by any person, entity or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), or any comparable successor provisions), of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20 percent or more of either the outstanding shares of common stock of Constellation Energy Group or the combined voting power of Constellation Energy Group’s then outstanding shares of voting securities entitled to a vote generally, or (ii) the consummation of, following the approval by the stockholders of Constellation Energy Group of a reorganization, merger, or consolidation of Constellation Energy Group, in each case, with respect to which persons who were stockholders of Constellation Energy Group immediately prior to such reorganization, merger or consolidation do not, immediately thereafter, own more than 50 percent of the combined voting power entitled to vote generally in the election of directors of the reorganized, merged or consolidated entity’s then outstanding securities, or (iii) a liquidation or dissolution of Constellation Energy Group or the sale of substantially all of its assets, or (iv) a change of more than one-half of the members of the Board of

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Directors of Constellation Energy Group within a 90-day period for reasons other than the death, disability, or retirement of such members.

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 adversely affect the rights of any participant without such participant’s prior written consent.

11.Miscellaneous.     The plan year and the performance year shall be the same and shall be the calendar year.

Any payments made under this Plan are not considered as earnings 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.

None of the payments provided under this Plan which are deferred shall be subject to alienation or assignment by any participant or beneficiary nor shall any of them be subject to attachment or garnishment or other legal process except to the extent specifically mandated and directed by applicable State or Federal statute.  Payment shall be made only into the hands of the participant or beneficiary entitled to receive the same or into the hands of his or her authorized legal representative.  Deposit of any sum into any financial institution to the credit of the participant or beneficiary entitled thereto shall constitute payment into his or her hands.  Notwithstanding the foregoing, at the request of the participant or beneficiary or as required by law, such sums as may be requisite for payment of any estimated or currently accrued income tax liability may be withheld and paid over to the governmental entity entitled to receive the same.

Participation in this Plan shall not constitute a contract of employment between the Company and any employee and shall not be deemed to be consideration for, inducement to, or a condition of employment of any person.  The deferral of any incentive compensation amounts pursuant to the provisions of the Plan shall not be construed to give any employee the right to be retained in the employ of the Company or to interfere with the right of the company to terminate such employment at any time.

The Committee on Management intends to continue the Plan indefinitely but reserves the right to amend the Plan from time to time

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or to permanently discontinue it provided none of these, nor any suspension, may deprive the participants of any payment of amounts which were previously awarded at the time thereof.

In the event Constellation Energy Group becomes a party to a merger, consolidation, sale of substantially all of its assets or any other corporate reorganization in which Constellation Energy Group will not be the surviving corporation or in which the holders of the common stock of Constellation Energy Group will receive securities of another corporation (in any such case, the “New Company”), then the New Company shall assume the rights and obligations of Constellation Energy Group under this Plan.

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EX-10.(C)

Exhibit 10(c)

CONSTELLATION ENERGY GROUP, INC.

NONQUALIFIED DEFERRED COMPENSATION PLAN (PLAN)

1.Objective.  The objective of this Plan is to enable certain management employees of Constellation Energy Group and its subsidiaries to defer compensation.

2.Definitions.  All words beginning with an initial capital letter and not otherwise defined herein shall have the meaning set forth in the Employee Savings Plan.  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:

“Basic Compensation” means such compensation as set forth in the Employee Savings Plan, without regard to the Internal Revenue Code Section 401(a)(17) annual compensation limitation.

“Committee” means the Committee on Management of the Board of Directors of Constellation Energy Group.

“Constellation Energy Group” means Constellation Energy Group, Inc., a Maryland corporation, or its successor.

“Death Benefit Contributions” means the death benefit contributions described in Section 9.

“Deferred Compensation” means any compensation payable by Constellation Energy Group or its subsidiaries to a participant that is deferred under the provisions of this Plan.

“Employee Savings Plan” means the Constellation Energy Group, Inc. Employee Savings Plan as may be amended from time to time, or any successor plan.

“Executive Annual Incentive Plan” means the Executive Annual Incentive Plan of Constellation Energy Group, Inc. as may be amended from time to time, or any successor plan, and/or any other incentive plan designated in writing by the Plan Administrator.

“Incentive Award” means an award granted under the Executive Annual Incentive Plan or the Senior Management Annual Incentive Plan.

“Matching Contributions” means the matching contributions described in Section 8.

“Plan Accounts” means amounts of a participant’s Deferred Compensation, Matching Contributions, and earnings under the Plan.

“Plan Administrator” means, as set forth in Section 3, the Vice President — Human Resources of Constellation Energy Group, (or the Vice-President succeeding to that function).

“Rabbi Trust” means the trust established by Constellation Energy Group pursuant to Grantor Trust Agreement dated as of April 30, 1999 between Constellation Energy Group and T. Rowe Price Trust Company.

“Rollover Contributions” means the rollover contributions described in Section 10.

“Senior Management Annual Incentive Plan” means the Senior Management Annual Incentive Plan of Constellation Energy Group, Inc. as may be amended from time to time, or any successor plan, and/or any other incentive plan designated in writing by the Plan Administrator.

“Termination From Employment with Constellation Energy Group” means a participant’s separation from service with Constellation Energy Group or a subsidiary of Constellation Energy Group; however, a participant’s transfer of employment to or from a subsidiary of Constellation Energy Group shall not constitute a Termination From Employment with Constellation Energy Group.

3.Plan Administration.  The Vice President — Human Resources of Constellation Energy Group, (or the Vice-President succeeding to that function) is the Plan Administrator and has the sole authority (except as specified otherwise herein) to interpret the Plan, and, in general, to make all other determinations advisable for the administration of the Plan to achieve its stated objective.

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Appeals of written decisions by the Plan Administrator may be made to the Committee.  Decisions by the Committee shall be final and not subject to further appeal.  The Plan Administrator shall have the power to delegate all or any part of his/her duties to one or more designees, and to withdraw such authority, by written designation.

4.Eligibility and Participation.  Each officer or key employee of Constellation Energy Group or its subsidiaries, or employees of Constellation Energy Group or its subsidiaries who hold senior management level positions, may be designated in writing by the Plan Administrator as eligible to participate with respect to one or more of the provisions of Sections 5, 6, 7, 8, 9 and 10, which designation will also indicate whether all or part of such participant’s Plan Accounts will be held in the Rabbi Trust.  Once designated, eligibility shall continue until such designation is withdrawn at the discretion and by written order of the Plan Administrator.  Notwithstanding subsequent withdrawal of eligibility of an employee, such an employee with Plan Accounts will remain a participant of the Plan, except that no further deferrals of compensation under the Plan are permitted.  While designated as eligible with respect to one or more of the provisions of Sections 5, 6, 7, 8, 9 or 10, an employee may participate in the Plan to the extent set forth in such designation.

5.Basic Compensation Deferral Election.  Unless otherwise designated in writing by the Plan Administrator, a participant may defer Basic Compensation as set forth in this Section 5.  A participant may elect to defer up to 15% of monthly Basic Compensation.  A participant may also elect to defer up to 100% of Basic Compensation, if any, in excess of the dollar limitation set forth in Internal Revenue Code Section 401(a)(17) (as adjusted by the Commissioner for increases in the cost of living in accordance with Internal Revenue Code Section 401(a)(17)(B)).  Any deferrals shall be in 1% multiples, or in such other manner established by the Plan Administrator from time to time, subject to adjustment as necessary to provide for any required withholding taxes.  Such election shall

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be made by notification in the form and manner established by the Plan Administrator from time to time, and shall be effective as of the beginning of the month following the month during which the election is received by the Plan Administrator.  Such election may be revoked by notification in the form and manner established by the Plan Administrator from time to time, and shall be effective as of the beginning of the month following the month during which the revocation is received by the Plan Administrator.

5(a).Special Provisions for Employees of Nine Mile Point Nuclear Station, LLC.  A participant may elect to defer up to 25% of monthly base salary (as defined from time to time by the Plan Administrator).  Any deferrals shall be in 5% multiples, subject to adjustment as necessary to provide for any required withholding taxes.  Such election shall be made in December by notification in the form and manner established by the Plan Administrator from time to time, and shall be effective on January 1 following the date of the notification.  For a new participant who becomes eligible during the calendar year, an election must be made within 30 days of becoming eligible, and the election shall be effective as of the beginning of the month following the month during which the election is received by the Plan Administrator.  Any election may be revoked by notification in the form and manner established by the Plan Administrator from time to time, and shall be effective as of January 1 of the year following receipt of the notification by the Plan Administrator.

6.Incentive Award Deferral Election.  A participant may elect to defer Incentive Award compensation in 1% multiples (10% multiples for employees of Nine Mile Point Nuclear Station, LLC), or in such other manner established by the Plan Administrator from time to time, subject to adjustment as necessary to provide for any required withholding taxes.  Such election shall be made annually by notification in the form and manner established by the Plan Administrator from time to time.  Such annual election shall be made prior to the Incentive Award performance year, and shall be effective as of the first day of such performance year.  If a participant initially becomes eligible

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to participate in the Plan during a performance year, the election for such performance year must be made prior to the date the participant initially becomes eligible to participate in the Plan, and shall be effective on such date.  Elections under this Section are irrevocable once effective.

7.Other Deferral Election.  A participant may elect to defer, in 1% multiples, other forms of compensation that are designated in writing by the Plan Administrator.  Such election must be made prior to the date the compensation is earned by the participant, by notification in the form and manner established by the Plan Administrator from time to time.  Such election is effective as of the date the compensation is earned.  Elections under this Section are irrevocable once effective.

8.Matching Contributions. Matching Contributions are made by Constellation Energy Group to the Plan in an amount equal to (i) up to the rate of Company Matching Contributions under the Employee Savings Plan multiplied by a participant’s monthly Basic Compensation deferral, less (ii) the amount of Company Matching Contributions made to the Employee Savings Plan on behalf of such participant with respect to such month.  Employees of Nine Mile Point Nuclear Station, LLC are not eligible to receive Matching Contributions.

9.Death Benefit Contribution.  Constellation Energy Group made contributions to separate Plan Account balances during 2001 on behalf of certain participants in connection with modifications made to the Company’s management death benefit program.  With respect to a participant, such contribution and related earnings are forfeited and not subject to distribution upon the participant’s Termination From Employment with Constellation Energy Group prior to meeting the early retirement eligibility provisions under the Pension Plan of Constellation Energy Group, Inc.; provided, however, no amount will be forfeited in the event of a participant’s death prior to Termination From Employment.

10.Rollover Contributions.  A participant may rollover the participant’s benefit under the Constellation Energy Group, Inc. Supplemental Pension Plan, Senior Executive Supplemental Plan,

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Senior Management Pension Plan, Senior Management Supplemental Pension Plan, or the Benefit Restoration Plan (collectively, SERPs), upon the participant’s retirement under a SERP, but for the Benefit Restoration Plan only if the present value of such participant’s benefit under that plan is at least $50,000.

11.Plan Accounts.  Deferred Compensation, Matching Contributions, Death Benefit Contributions and Rollover Contributions shall be (i) credited to participant Plan Accounts as soon as practicable; (ii) to the extent designated by the Plan Administrator, held for the benefit of the participant in the Rabbi Trust; and (iii) credited with earnings at the T. Rowe Price Prime Reserve Fund rate.  However, a participant may elect (by notification in the form and manner established by the Plan Administrator from time to time) to have all or a portion of his/her Plan Accounts credited with earnings at a rate equal to the T. Rowe Price Prime Reserve Fund rate, the T. Rowe Price New Income Fund rate, or one or more of the rates earned by investment options available under the Employee Savings Plan, except the Common Stock Fund and the Interest Income Fund.  Earnings are credited to Plan Accounts commencing on the day the Deferred Compensation, Matching Contributions, Death Benefit Contributions and Rollover Contributions are credited to the Plan Accounts. Plan Accounts will be valued daily in the same manner as for Investment Funds under the Employee Savings Plan.

A participant may elect to change the investment option of future Deferred Compensation and Matching Contributions, which election shall be effective when the next Deferred Compensation contributions and/or Matching Contributions are credited to the participant’s Plan Accounts.  A participant may elect to reallocate to other investment options current Plan Accounts, which election shall be effective at the same time as, and valued in accordance with, the interfund transfer provisions under the Employee Savings Plan.  Such elections shall be made by notification in the form and manner established by the Plan Administrator from time to time.

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12.Distributions of Plan Accounts.  Distributions of Plan Accounts shall be made in cash only, and to the extent designated by the Plan Administrator, from the Rabbi Trust.

Prior to the end of the thirtieth (30^th) calendar  day after the date of a participant’s Termination From Employment with Constellation Energy Group, such participant must elect the timing of distributions of his/her Plan Accounts.  The participant may elect (by notification in the form and manner established by the Plan Administrator from time to time) to begin distributions (i) in the calendar year following the calendar year of the participant’s Termination From Employment with Constellation Energy Group, (ii) in the year following the year in which a participant attains age 70-1/2, if later, or (iii) any calendar year between (i) and (ii).  A participant may elect (by notification in the form and manner established by the Plan Administrator from time to time) to receive distributions in a single payment or in annual installments during a period not to exceed twenty-five years.  Such annual installments shall be made on a ratable basis, except the participant may elect a different initial installment payment (expressed as a percentage of the participant’s Plan Account balance).  The single payment or the first installment payment, whichever is applicable, shall be made within the first sixty (60) days of the calendar year elected for distribution.  Subsequent installments, if any, shall be made within the first sixty (60) days of each succeeding calendar year until the participant’s Plan Accounts have been paid.  In the event no election is made prior to the end of the thirtieth (30^th) calendar day after the date of a participant’s Termination From Employment with Constellation Energy Group, a participant shall receive a distribution in a single payment within the first sixty (60) days of the following year.  Earnings are credited to Plan Accounts through the date of distribution, and amounts held for installment payments shall continue to be credited with earnings, as specified in Section 11.

A participant’s distribution election is irrevocable on the thirtieth (30^th) calendar day after the date of a participant’s Termination From

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Employment with Constellation Energy Group; provided, however a participant may subsequently make a one-time post-employment termination distribution election to receive a lump-sum payout of the participant’s remaining balance, provided such election is made no later than December 31 of the year that is at least one full calendar year prior to the distribution date, and is in the form and manner established by the Plan Administrator.

If a participant dies, the entire unpaid balance of his/her Plan Accounts shall be paid to the beneficiary(ies) designated by the participant by notification in the form and manner established by the Plan Administrator from time to time or, if no designation was made, to the estate of the participant.  Payment shall be made within sixty (60) days after notice of death is received by the Plan Administrator, unless prior to the end of the thirtieth (30^th) calendar day after the date of the participant’s Termination From Employment with Constellation Energy Group, the participant elected (in the form and manner established by the Plan Administrator from time to time) a delayed and/or installment distribution option for such beneficiary(ies); provided, however that (i) such a distribution option election shall be effective only if the value of the participant’s Plan Accounts is more than $50,000 on the date of the participant’s death; and (ii) the final distribution must be made to such beneficiary(ies) no later than the earlier of (a) 15 years after the participant’s death or (b) 25 years minus the years for which installments were paid to the participant before the participant’s death.  After the end of the thirtieth (30^th) calendar day after the date of a participant’s Termination From Employment with Constellation Energy Group, a distribution option election for a particular beneficiary is irrevocable; provided, however, that the participant may make a distribution option election for a new beneficiary who is initially designated after the participant’s Termination From Employment with Constellation Energy Group, and such election is irrevocable with respect to the new beneficiary.

In the event a participant’s deferred Incentive Award is credited to the Plan after the participant’s death, such Incentive Award shall be

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either paid to his/her beneficiary(ies), or if a delayed and/or installment distribution option was elected for such beneficiary(ies), paid as part of the aggregate Plan Accounts in accordance with such election.

Upon the death of a participant’s beneficiary for whom a delayed and/or installment distribution option was elected, the entire unpaid balance of the participant’s Plan Accounts shall be paid to the beneficiary(ies) designated by the participant’s beneficiary by notification in the form and manner established by the Plan Administrator from time to time or, if no designation was made, to the estate of the participant’s beneficiary.  Payment shall be made within sixty (60) days after notice of death is received by the Plan Administrator.

Notwithstanding anything herein contained to the contrary, the Committee shall have the right in its sole discretion to vary the manner and timing of distributions, and may make such distributions in a single payment or over a shorter or longer period of time than that elected by a participant.

13.Beneficiaries.  A participant shall have the right to designate a beneficiary(ies) who is to receive a distribution(s) pursuant to Section 12 in the event of the death of the participant.  A participant’s beneficiary(ies) for whom a delayed and/or installment distribution option was elected shall have the right to designate a beneficiary(ies) who is to receive a distribution pursuant to Section 12 in the event of the death of the participant’s beneficiary(ies).

Any designation, change or recision of the designation of beneficiary shall be made by notification in the form and manner established by the Plan Administrator from time to time.  The last designation of beneficiary received by the Plan Administrator shall be controlling over any testamentary or purported disposition by the participant (or, if applicable, the participant’s beneficiary(ies)), provided that no designation, recision or change thereof shall be effective unless received by the Plan Administrator prior to the death of the participant (or, if applicable, the participant’s beneficiary(ies)).

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If the designated beneficiary is the estate, or the executor or administrator of the estate, of the participant (or, if applicable, the participant’s beneficiary(ies)), a distribution pursuant to Section 12 may be made to the person(s) or entity (including a trust) entitled thereto under the will of the participant (or, if applicable, the participant’s beneficiary(ies)), or, in the case of intestacy, under the laws relating to intestacy.

A participant’s beneficiary(ies) for whom a delayed and/or installment distribution option was elected shall have the right, after the death of the participant, to make investment elections or changes in investment elections with respect to a participant’s Plan Accounts to the same extent available to the participant pursuant to Section 11.  A beneficiary(ies) of the participant’s beneficiary(ies) shall have no right to make any investment election or change in investment election pursuant to Section 11 with respect to a participant’s Plan Accounts.

14.Valuation of Interest.  The Plan Administrator shall cause the value of a participant’s Plan Accounts, at least once per year as of December 31, to be determined separately and be reported to Constellation Energy Group and the participant (or, if applicable, the participant’s beneficiary(ies)).  Valuation of a participant’s Plan Accounts shall be determined in accordance with the procedures contained in the Employee Savings Plan.

15.Withdrawals.  No withdrawals of Plan Accounts may be made, except a participant may at any time request a hardship withdrawal from his/her Plan Accounts if he/she has incurred an unforeseeable financial emergency.  An unforeseeable financial emergency is defined as severe financial hardship to the participant resulting from a sudden and unexpected illness or accident of the participant (or of his/her dependents), loss of the participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the participant.  The need to send a child to college or the desire to purchase a

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home are not considered to be unforeseeable emergencies.  The circumstance that will constitute an unforeseeable emergency will depend upon the facts of each case.

A hardship withdrawal will be permitted by the Plan Administrator only as necessary to satisfy an immediate and heavy financial need.  A hardship withdrawal may be permitted only to the extent reasonably necessary to satisfy the financial need.  Payment may not be made to the extent that such hardship is or may be relieved (i) through reimbursement or compensation by insurance or otherwise, (ii) by liquidation of the participant’s assets, to the extent the liquidation of such assets would not itself cause severe financial hardship, or (iii) by cessation of deferrals under the Plan.

The request for hardship withdrawal shall be made by notification in the form and manner established by the Plan Administrator from time to time.  Such hardship withdrawal will be permitted only with approval of the Plan Administrator.  The participant will receive a lump sum payment after the Plan Administrator has had reasonable time to consider and then approve the request.

16.Miscellaneous.  A participant’s Plan Accounts shall not be subject to alienation or assignment by any participant or beneficiary nor shall any of them be subject to attachment or garnishment or other legal process except (i) to the extent specially mandated and directed by applicable State or Federal statute; and (ii) as requested by the participant or beneficiary to satisfy income tax withholding or liability.

This Plan may be amended from time to time or suspended or terminated at any time at the written direction of the Committee.  No amendment to or termination of this Plan shall impair the rights of any participant or beneficiary with respect to amounts in his/her Plan Accounts before the date of such amendment or termination.

Participation in this Plan shall not constitute a contract of employment between Constellation Energy Group and any person and shall not be

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deemed to be consideration for, or a condition of, continued employment of any person.

The Plan, notwithstanding the creation of the Rabbi Trust, is intended to be unfunded for purposes of Title I of the Employee Retirement Income Security Act of 1974.  Constellation Energy Group shall make contributions to the Rabbi Trust in accordance with the terms of the Rabbi Trust.  Any funds which may be invested and any assets which may be held to provide benefits under this Plan shall continue for all purposes to be a part of the general funds and assets of Constellation Energy Group and no person other than Constellation Energy Group shall by virtue of the provisions of this Plan have any interest in such funds and assets.  To the extent that any person acquires a right to receive payments from Constellation Energy Group under this Plan, such rights shall be no greater than the right of any unsecured general creditor of Constellation Energy Group.

In the event Constellation Energy Group becomes a party to a merger, consolidation, sale of substantially all of its assets or any other corporate reorganization in which Constellation Energy Group will not be the surviving corporation or in which the holders of the common stock of Constellation Energy Group will receive securities of another corporation (in any such case, the “New Company”), then the New Company shall assume the rights and obligations of Constellation Energy Group under this Plan.

This Plan shall be governed in all respects by Maryland law.

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Amendment to the

Constellation Energy Group, Inc.

Nonqualified Deferred Compensation Plan (Plan)

Notwithstanding anything in Section 12 of the Plan to the contrary, for Rollover Contributions effective December 31, 2001 in connection with employment terminations related to management restructuring announced late in 2001, all or part of such Rollover Contributions may be distributed to a participant in 2002 if the participant provides notification by December 31, 2001 in the form and manner established by the Plan Administrator.

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EX-10.(D)

Exhibit 10(d)

Constellation Energy Group, Inc.

Deferred Compensation Plan

For Non-Employee Directors

1.Objective.  The objective of this Plan is to offer a portion of the Compensation of non-employee Directors of Constellation Energy Group in the form of Stock Units, thereby promoting a greater identity of interest between Constellation Energy Group’s non-employee Directors and its stockholders, and to enable such Directors to defer receipt of their Compensation that is payable in cash.

2.Definitions.  As used herein, the following terms will have the meaning specified below:

“Annual Retainer” means the amount payable by Constellation Energy Group to a Director as annual compensation for performance of services as a Director, and includes Committee Chair retainers.  All other amounts (including without limitation Board/committee meeting fees, and expense reimbursements) shall be excluded in calculating the amount of the Annual Retainer.

“Board” means the Board of Directors of Constellation Energy Group.

“Cash Account” means an account by that name established pursuant to Section 7.  The maintenance of Cash Accounts is for bookkeeping purposes only.

 “Change in Control” means (i) the purchase or acquisition by any person, entity or group of persons (within the meaning of section 13(d) or 14(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), or any comparable successor provisions), of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20 percent or more of either the outstanding shares of common stock of Constellation Energy Group or the combined voting power of Constellation Energy Group’s then outstanding shares of voting securities entitled to a vote generally, or (ii) the consummation of, following the approval by the stockholders of Constellation Energy Group of a reorganization, merger or consolidation of Constellation Energy Group, in each case, with respect to which persons who were stockholders of Constellation Energy Group immediately prior to such reorganization, merger or consolidation do not, immediately thereafter, own more than 50 percent of the combined voting power entitled to vote generally in the election of directors of the reorganized, merged or consolidated entity’s then

outstanding securities, or (iii) a liquidation or dissolution of Constellation Energy Group or the sale of substantially all of its assets, or (iv) a change of more than one-half of the members of the Board within a 90-day period for reasons other than the death, disability, or retirement of such members.

“Committee” means the Committee on Management of the Board.

“Common Stock” means the common stock, without par value, of Constellation Energy Group.

“Compensation” means any Annual Retainer and meeting fees payable by Constellation Energy Group to a participant in his/her capacity as a Director.  Compensation excludes expense reimbursements paid by Constellation Energy Group to a participant in his/her capacity as a Director.

“Constellation Energy Group” means Constellation Energy Group, Inc., a Maryland corporation, or its successor.

“Deferred Cash Compensation” means any cash Compensation that is voluntarily deferred by a participant pursuant to Section 6.

“Director” means a member of the Board who is not an employee of Constellation Energy Group or any of its subsidiaries/ affiliates.

“Disability” or “Disabled” means that the Plan Administrator has determined that the participant is unable to fulfill his/her responsibilities of Board membership because of illness or injury.  For purposes of this Plan, a participant’s eligibility to participate shall be deemed to have terminated on the date he/she is determined by the Plan Administrator to be Disabled.

“Earnings” means, with respect to the Cash Account, hypothetical interest credited to the Cash Account.

“Earnings” means, with respect to the Stock Account, hypothetical dividends credited to the Stock Account.

“Fair Market Value” means, as of any specified date, the average closing price of a share of Common Stock, reported in “New York Stock Exchange Composite Transactions” as published in the Eastern Edition of The Wall Street Journal averaged for the most recent 20 days during which Common Stock was traded on  the New York Stock Exchange (including such valuation date if a trading date).

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“Plan Accounts” means a participant’s Cash Account and/or Stock Account.  The maintenance of Plan Accounts is for bookkeeping purposes only.

“Plan Administrator” means, as set forth in Section 3, the Board.

“Stock Account” means an account by that name established pursuant to Section 8.  The maintenance of Stock Accounts is for bookkeeping purposes only.

“Stock Unit(s)” means the share equivalents credited to a Participant’s Stock Account pursuant to Section 8.  The use of Stock Units is for bookkeeping purposes only; the Stock Units are not actual shares of Common Stock.  Constellation Energy Group will not reserve or otherwise set aside any Common Stock for or to any Stock Account.

3.Plan Administration.

(i)            Plan Administrator — The Plan is administered by the Board, who has sole authority to interpret the Plan, and, in general, to make all other determinations advisable for the administration of the Plan to achieve its stated objective.  Decisions by the Plan Administrator shall be final and binding upon all persons for all purposes.  The Plan Administrator shall have the power to delegate all or any part of its non-discretionary duties to one or more designees, and to withdraw such authority, by written designation.

(ii)           Amendment — This Plan may be amended from time to time or suspended or terminated at any time, at the written direction of the Plan Administrator.  However, amendments required to keep the Plan in compliance with applicable laws and regulations may be made by the Vice President — Human Resources of Constellation Energy Group (or other vice president succeeding to that function) on advice of counsel.  Nothing herein creates a vested right.

(iii)          Indemnification — The Plan Administrator (and its designees), Chairman of the Board, Chief Executive Officer, President, and Vice President-Human Resources of Constellation Energy Group and all other employees of Constellation Energy Group or its subsidiaries/affiliates whose assigned duties include matters under the Plan, shall be indemnified by Constellation Energy Group or its subsidiaries /affiliates or from proceeds under insurance policies purchased by Constellation Energy Group or its

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subsidiaries/affiliates, against any and all liabilities arising by reason of any act or failure to act made in good faith pursuant to the provisions of the Plan, including expenses reasonably incurred in the defense of any related claim.

4.Eligibility and Participation.

(i)Mandatory participation — A Director, at the discretion of the Board, may be required at such times designated by the Board to participate in this Plan with respect to the receipt of all or part of his/her Compensation in the form of Stock Units under Section 5 of the Plan.

(ii)Voluntary participation – A Director is eligible to participate in the Plan by electing to defer all or certain portions of the participant’s Compensation, that is payable in cash, under Section 6 of the Plan, while so classified.

(iii)Termination of participation — Eligibility to participate shall terminate on the date the participant ceases to be a Director.  Notwithstanding termination of eligibility, such person with Plan Accounts will remain a participant of the Plan, solely for purposes of the administration of existing Plan Accounts, and no additional Stock Units will be granted and no further deferrals of cash Compensation under the Plan will be permitted.

5.Mandatory Stock Units.  To the extent designated from time to time by the Board as set forth in Section 4(i), the Stock Account of a participant will be credited on January 1 of each applicable calendar year with Stock Units equal to the number of shares of Common Stock (including fractions of a share) that could have been purchased, with the applicable percentage (as designated by the Board) of the participant’s Annual Retainer for such calendar year, at Fair Market Value on such January 1.

If a participant initially becomes eligible to participate in the Plan during such applicable calendar year, the Stock Account of the participant for such calendar year will be credited, on the date that is the first day of the calendar month after the participant initially becomes eligible to participate in the Plan, with Stock Units equal to the number of shares of Common Stock (including fractions of a share) that could have been purchased at Fair Market Value on such date, with an amount equal to (i) the applicable percentage (as designated by the Board) of the participant’s Annual Retainer multiplied by (ii) a

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fraction the numerator of which is the number of full calendar months in the calendar year on and after such date, and the denominator of which is 12.

The Stock Account will be maintained pursuant to Section 8.

6.Cash Compensation Deferral Election.  A participant may elect to defer none, all, fifty percent (50%), or seventy-five percent (75%) of his/her other Compensation that is payable in cash (i.e., one hundred percent (100%) of all other Compensation that is not subject to any mandatory Stock Units). A participant’s cash Compensation deferral election with respect to the Annual Retainer shall specify whether the deferred Annual Retainer is to be credited to the Cash Account or to the Stock Account.  All other Cash Compensation that a participant elects to defer will be credited to the Cash Account.

Such election shall be made by written notification to the Vice President-Human Resources of Constellation Energy Group (or other vice president succeeding to that function).  Such election shall be made prior to the calendar year during which the applicable cash Compensation is payable, and shall be effective as of the first day of such calendar year.  If a participant initially becomes eligible to participate in the Plan during a calendar year, the election for such calendar year must be made within thirty (30) calendar days after the date the participant initially becomes eligible to participate in the Plan, and shall be effective with respect to Compensation earned after the date the election is received by the Vice President-Human Resources of Constellation Energy Group (or other vice president succeeding to that function).  Elections under this Section shall remain in effect for all succeeding calendar years until revoked.  Elections may be revoked by written notification to the Vice President-Human Resources of Constellation Energy Group (or other vice president succeeding to that function), and shall be effective as of the first day of the calendar year following the calendar year during which the revocation is received by such Vice President.

Notwithstanding anything herein contained to the contrary, the Plan Administrator shall have the right in its sole discretion to permit a participant to defer other percentages of his/her Annual Retainer and/or other Compensation that is payable in cash.

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7.Cash Accounts.  The Board may specify that cash Compensation that consists of the Annual Retainer that a participant has elected to defer into the Cash Account is credited to the participant’s Cash Account on January 1 (or if later, the date the participant’s initial election to participate in the Plan becomes effective). All other cash Compensation that a participant has elected to defer is credited to the participant’s Cash Account on each date such cash Compensation would otherwise have been paid to the Director.  A participant’s Cash Account shall be credited with earnings at the rate earned by the Interest Income Fund under the Constellation Energy Group, Inc. Employee Savings Plan, and computed in the same manner as under such plan.  Earnings are credited to the Cash Account commencing on the date the applicable Deferred Cash Compensation is credited to the Cash Account.

8.Stock Accounts.  The Board may specify that cash Compensation that consists of the Annual Retainer that a participant has elected to defer into the Stock Account is credited to the participant’s Stock Account on January 1 (or if later, the date the participant’s initial election to participate in the Plan becomes effective).  All other cash Compensation that a participant has elected to defer into the Stock Account is credited to the participant’s Stock Account  on each date such cash Compensation would otherwise have been paid to the Director.  A participant’s Stock Account shall be credited with Stock Units equal to the number of shares of Common Stock (including fractions of a share) that could have been purchased with such Deferred Cash Compensation, at Fair Market Value on such date.  Grants of mandatory Stock Units are credited to the Stock Account as set forth in Section 5.

As of any dividend distribution date for the Common Stock, the participant’s Stock Account shall be credited with additional Stock Units equal to the number of shares of Common Stock (including fractions of a share) that could have been purchased, at the closing price of a share of Common Stock on such date as reported in “New York Stock Exchange Composite Transactions” as published in the Eastern Edition of The Wall Street Journal, with the amount which would have been paid as dividends on that number of shares (including fractions of a share) of Common Stock which is equal to the number of Stock Units then credited to the participant’s Stock Account.

In the event of any change in the outstanding shares of Common Stock by reason of any stock dividend or split, recapitalization, combination or exchange of shares or

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other similar changes in the Common Stock, then appropriate adjustments shall be made in the number of Stock Units in each participant’s Stock Account.  Such adjustments shall be made effective on the date of the change related to the Common Stock.

9.Distributions of Plan Accounts.  Distributions of Plan Accounts shall be made in cash only, from the general assets of Constellation Energy Group.

A participant may elect (by notification in the form and manner established by the Vice President-Human Resources of Constellation Energy Group (or other Vice President succeeding to that function) from time to time) to begin distributions (i) in the calendar year following the calendar year that eligibility to participate terminates, (ii) in the calendar year following the calendar year in which a participant attains age 70, if later, or (iii) any calendar year between (i) and (ii).  Such election must be made prior to the end of the calendar year in which eligibility to participate terminates.  Alternatively, a participant who reaches age 70 while still eligible to participate may elect to begin distributions, in the calendar year following the calendar year that the participant reaches age 70, of amounts in his/her Plan Accounts as of the end of the calendar year the participant reaches age 70.  Such election must be made prior to the end of the calendar year in which the participant reaches age 70, and a distribution election to receive any subsequently deferred amounts beginning in the calendar year following the calendar year that eligibility to participate terminates, must be made prior to the end of the calendar year in which eligibility to participate terminates.

A participant may elect (by notification in the form and manner established by the Vice President-Human Resources of Constellation Energy Group (or other vice President succeeding to that function) from time to time) to receive distributions in a single payment or in annual installments during a period not to exceed fifteen years.  The single payment or the first installment payment, whichever is applicable, shall be made within the first sixty (60) calendar days of the calendar year elected for distribution.  Subsequent installments, if any, shall be made within the first sixty (60) calendar days of each succeeding calendar year until the participant’s Cash Account has been paid out.

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In the event applicable elections are not timely made, a participant shall receive a distribution in a single payment within the first sixty (60) calendar days of the calendar year following the calendar year that eligibility to participate terminates.

The value of the Stock Account, which is equal to the number of Stock Units in the Stock Account multiplied by the Fair Market Value on the date on which the participant’s eligibility to participate terminates (or, the date that is the last day of the calendar year during which the participant reaches age 70, for a participant who elects to begin distributions while still eligible to participate), is transferred to the Cash Account on such date.  Earnings are credited to the Cash Account through the date of distribution, and amounts held for installment payments shall continue to be credited with Earnings.  The value of the Cash Account that is payable in cash on the date of the single payment distribution is equal to the balance in the Cash Account on the date that is no earlier than five (5) calendar days prior to the day of such distribution (“Distribution Valuation Date”).  The amount of any cash distribution to be made in installments from the Cash Account will be determined by multiplying (i)  the balance in such Cash Account on the Distribution Valuation Date by (ii)  a fraction, the numerator of which is one and the denominator of which is the number of installments in which distributions remain to be made (including the current distribution).

If a participant dies or becomes Disabled, the entire unpaid balance of his/her Plan Accounts shall be paid to the beneficiary(ies) designated by the participant by notification in the form and manner established by the Vice President-Human Resources of Constellation Energy Group (or other vice president succeeding to that function) from time to time or, if no designation was made, in the event of death, to the estate of the participant, and in the event of Disability, to the participant.  Payment shall be made within sixty (60) calendar days after notice of death or Disability is received by such Vice President, unless prior to the participant’s death or Disability, the participant elected (in the form and manner established by the Vice President-Human Resources of Constellation Energy Group (or other vice president succeeding to that function) from time to time) a delayed and/or installment distribution option for such beneficiary(ies); provided, however that (i) such a distribution option election shall be effective only if the value of the participant’s Plan Accounts is more than

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$50,000 on the date of the participant’s death or Disability; and (ii) the final distribution must be made to such beneficiary(ies) no later than 15 years after the participant’s death or Disability.  After the end of the calendar year that a participant’s eligibility to participate terminates, a distribution option election for a particular beneficiary is irrevocable; provided, however, that the participant may make a distribution option election for a new beneficiary who is initially designated after the participant’s eligibility to participate terminates, and such election is irrevocable with respect to the new beneficiary.

The value of the Stock Account, which is equal to the number of Stock Units in the Stock Account multiplied by the Fair Market Value on the date of the participant’s death or Disability, is transferred to the Cash Account on such date.  Earnings are credited to the Cash Account through the date of distribution, and amounts held for installment payments shall continue to be credited with Earnings.  The value of the Cash Account that is payable in cash on the date of the single payment distribution is equal to the balance in the Cash Account on the date that is no earlier than five (5) calendar days prior to the day of such distribution (“Beneficiary Distribution Valuation Date”).  The amount of any cash distribution to be made in installments from the Cash Account will be determined by multiplying (i) the balance in such Cash Account on the Beneficiary Distribution Valuation Date by (ii) a fraction, the numerator of which is one and the denominator of which is the number of installments in which distributions remain to be made (including the current distribution).

Upon the death of a participant’s beneficiary for whom a delayed and/or installment distribution option was elected, the entire unpaid balance of the participant’s Cash Account shall be paid to the beneficiary(ies) designated by the participant’s beneficiary by notification in the form and manner established by the Vice President-Human Resources of Constellation Energy Group (or other vice president succeeding to that function) from time to time or, if no designation was made, to the estate of the participant’s beneficiary.  Payment shall be made within sixty (60) calendar days after notice of death is received by such Vice President.  The value of the Cash Account that is payable in cash is equal to the balance in the Cash Account on the date that is no earlier than five (5) calendar days prior to the day of such distribution.

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Notwithstanding anything herein contained to the contrary, the Plan Administrator shall have the right in its sole discretion to (i) vary the manner and timing of distributions of a participant or beneficiary entitled to a distribution under this Section 9, and may make such distributions in a single payment or over a shorter or longer period of time than that elected by a participant; and (ii) vary the period during which the closing price of Common Stock is referenced to determine the value of the Stock Account that is transferred to the Cash Account on the date on which the participant’s eligibility to participate terminates.  Any affected participants will not participate in exercising such discretion.

10.Beneficiaries. A participant shall have the right to designate, change or rescind a beneficiary(ies) who is to receive a distribution(s) pursuant to Section 9 in the event of the death or Disability of the participant.  A participant’s beneficiary(ies) for whom a delayed and/or installment distribution option was elected shall have the right to designate a beneficiary(ies) who is to receive a distribution pursuant to Section 9 in the event of the death of the participant’s beneficiary(ies).

Any designation, change or recision of the designation of beneficiary shall be made by notification in the form and manner established by the Vice President-Human Resources of Constellation Energy Group (or other vice president succeeding to that function) from time to time.  The last designation of beneficiary received by such Vice President shall be controlling over any testamentary or purported disposition by the participant (or, if applicable, the participant’s beneficiary(ies)), provided that no designation, recision or change thereof shall be effective unless received by such Vice President prior to the death or Disability (whichever is applicable) of the participant (or, if applicable, the death of the participant’s beneficiary(ies)).

If the designated beneficiary is the estate, or the executor or administrator of the estate, of the participant (or, if applicable, the participant’s beneficiary(ies)), a distribution pursuant to Section 9 may be made to the person(s) or entity (including a trust) entitled thereto under the will of the participant (or, if applicable, the participant’s beneficiary(ies)), or, in the case of intestacy, under the laws relating to intestacy.

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11.Valuation of Plan Accounts.  The Plan Administrator shall cause the value of a participant’s Plan Accounts to be determined and reported to Constellation Energy Group and the participant at least once per year as of the last business day of the calendar year.  The value of the Stock Account will equal the number of Stock Units in the Stock Account multiplied by the closing price of a share of Common Stock on the last business day of the calendar year as reported in “New York Stock Exchange Composite Transactions” as published in the Eastern Edition of The Wall Street Journal.  The value of the Cash Account will equal the balance in the Cash Account on the last business day of the calendar year.

12.Withdrawals.  No withdrawals of Plan Accounts may be made, except a participant may at any time request a hardship withdrawal from his/her Plan Accounts if he/she has incurred an unforeseeable financial emergency.  An unforeseeable financial emergency is defined as severe financial hardship to the participant resulting from a sudden and unexpected illness or accident of the participant (or of his/her dependents), loss of the participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the participant.  The need to send a child to college or the desire to purchase a home are not considered to be unforeseeable emergencies.  The circumstance that will constitute an unforeseeable emergency will depend upon the facts of each case.

A hardship withdrawal will be permitted by the Plan Administrator only as necessary to satisfy an immediate and heavy financial need.  A hardship withdrawal may be permitted only to the extent reasonably necessary to satisfy the financial need.  Payment may not be made to the extent that such hardship is or may be relieved (i) through reimbursement or compensation by insurance or otherwise, (ii) by liquidation of the participant’s assets, to the extent the liquidation of such assets would not itself cause severe financial hardship, or (iii) by cessation of deferrals under the Plan.

The request for hardship withdrawal shall be made by notification in the form and manner established by the Plan Administrator from time to time.  Such hardship withdrawal will be permitted only with approval of the Plan Administrator.  The participant will receive a lump sum payment after the Plan Administrator has had reasonable time to consider and then approve the request.

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The value of the Stock Account for purposes of processing a hardship cash withdrawal is equal to the number of Stock Units in the Stock Account multiplied by the Fair Market Value on the date on which the hardship withdrawal is processed.  The value of the Cash Account for purposes of processing a hardship cash withdrawal is equal to the balance in the Cash Account on the date on which the hardship withdrawal is processed.

13.Change in Control.  The terms of this Section 13 shall immediately become operative, without further action or consent by any person or entity, upon a Change in Control, and once operative shall supersede and control over any other provisions of this Plan.  Upon the occurrence of a Change in Control followed within one year of the date of such Change in Control by the participant’s cessation of Board membership for any reason, such participant shall be paid the value of his/her Plan Accounts in a single, lump sum cash payment.  The value of the Stock Account, which is equal to the number of Stock Units in the Stock Account multiplied by the Fair Market Value on the date of the participant’s cessation of Board membership, is transferred to the Cash Account on such date.  Earnings are credited to the Cash Account through the date of distribution.  The value of the Cash Account that is payable in cash on the date of the single lump sum cash payment is equal to the balance in the Cash Account on the date that is no earlier than five (5) calendar days prior to the day of such distribution.  Such payment shall be made as soon as practicable, but in no event later than thirty (30) calendar days after the date of the participant’s cessation of Board membership.  On or 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 affect the rights of any participant or the operation of this Plan with respect to the balance in the participant’s Plan Accounts.

14.Withholding.  Constellation Energy Group may withhold to the extent required by law all applicable income and other taxes from amounts deferred or distributed under the Plan.

15.Copies of Plan Available.  Copies of the Plan and any and all amendments thereto shall be made available to all participants during normal business hours at the office of the Plan Administrator.

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16.Miscellaneous.

(i)Inalienability of benefits — Except as may otherwise be required by law or court order, the interest of each participant or beneficiary under the Plan cannot be sold, pledged, assigned, alienated or transferred in any manner or be subject to attachment or other legal process of whatever nature; provided, however, that any applicable taxes may be withheld from any cash benefit payment made under this Plan.

(ii)Controlling law — The Plan and its administration shall be governed by the laws of theState of Maryland, except to the extent preempted by federal law.

(iii)Gender and number — A masculine pronoun when used herein refers to both men and women and words used in the singular are intended to include the plural, and vice versa, whenever appropriate.

(iv)Titles and headings — Titles and headings to articles and sections in the Plan are placed herein solely for convenience of reference and in any case of conflict, the text of the Plan rather than such titles and headings shall control.

(v)References to law — All references to specific provisions of any federal or state law, rule or regulation shall be deemed to also include references to any successor provisions or amendments.

(vi)Funding and expenses — Benefits under the Plan are not vested or funded, and shall be paid out of the general assets of Constellation Energy Group.  To the extent that any person acquires a right to receive payments from Constellation Energy Group under this Plan, such rights shall be no greater than the right of any unsecured general creditor of Constellation Energy Group.  The expenses of administering the Plan will be borne by Constellation Energy Group.

(vii)Not a contract — Participation in this Plan shall not constitute a contract of employment or Board membership between Constellation Energy Group and any person and shall not be deemed to be consideration for, or a condition of, continued employment or Board membership of any person.

(viii)Successors — In the event Constellation Energy Group becomes a party to a merger, consolidation, sale of

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substantially all of its assets or any other corporate reorganization in which Constellation Energy Group will not be the surviving corporation or in which the holders of the common stock of Constellation Energy Group will receive securities of another corporation (in any such case, the “New Company”), then the New Company shall assume the rights and obligations of Constellation Energy Group under this Plan.

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EX-10.(H)

Exhibit 10 (h)

FORM OF

SEVERANCE AGREEMENTS

This Agreement is made the       day of         , 2002, by and between CONSTELLATION ENERGY GROUP, INC. (the “Company”) and [                         ] (the “Executive”), and is effective as of [            , 2002].

WHEREAS, the Company wishes to encourage the orderly succession of management in the event of a Change in Control (as hereinafter defined); and

WHEREAS, the Company desires to maintain a severance benefit for the Executive covering the period from the date of a Change in Control until the end of the twenty-four month period following the date of a Change in Control, to avoid the loss or the serious distraction of the Executive to the detriment of the Company and its stockholders prior to and during such period when the Executive’s undivided attention and commitment to the needs of the Company would be particularly important; and

WHEREAS, the Executive desires to devote the Executive’s time and energy for the benefit of the Company and its stockholders and not to be distracted as a result of a Change in Control.

NOW, THEREFORE, the parties agree as follows:

1.             Definitions.

1.1           Board. The term “Board” means the Board of Directors of the Company.

1.2           Change in Control. The term “Change in Control” means:

(i)            the purchase or acquisition by any person, entity or group of persons (within the meaning of section 13(d) or 14(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), or any comparable successor provisions), of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20 percent or more of either the outstanding shares of common stock of the Company or the combined voting power of the Company’s then outstanding shares of voting securities entitled to a vote generally, or

(ii)           the consummation of, following the approval by the Company’s stockholders of, a reorganization, merger or

consolidation of the Company, in each case, with respect to which persons who were stockholders of the Company immediately prior to such reorganization, merger or consolidation do not, immediately thereafter, own more than 50 percent of the combined voting power entitled to vote generally in the election of directors of the reorganized, merged or consolidated entity’s then outstanding securities, or

(iii)          a liquidation or dissolution of the Company or the sale of substantially all of its assets, or

(iv)          a change of more than one-half of the members of the Board within a 90-day period for reasons other than the death, disability, or retirement of such members.

1.3           Qualifying Termination.

(a)           The occurrence of any one or more of the following events within twenty-four calendar months after the date of a Change in Control shall constitute a “Qualifying Termination”:

(i)            The Company’s termination of the Executive’s employment without Cause (as defined in Section 1.7); or

(ii)           The Executive’s resignation for Good Reason (as defined in Section 1.6).

(b)           A Qualifying Termination shall not include a termination of employment by reason of death, disability, the Executive’s voluntary termination of employment without Good Reason, or the Company’s termination of the Executive’s employment for Cause.

1.4           Ineligible to Retire.  Ineligible to Retire, means an Executive who has not met the eligibility requirements for retirement under any Company or Affiliate supplemental non-qualified pension plan in which the Executive participated immediately prior to the occurrence of a Qualifying Termination.

1.5           Eligible to Retire.  Eligible to Retire, means an Executive who has met the eligibility requirements for retirement under any Company or Affiliate supplemental non-qualified pension plan in which the Executive participated immediately prior to the occurrence of a Qualifying Termination.

1.6           Good Reason.  Good Reason means, without the Executive’s express written consent, the occurrence after the date of a Change in Control of any one or more of the following:

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(a)           The assignment to the Executive of duties materially inconsistent with the Executive’s authorities, duties, responsibilities, and status (including offices, title and reporting relationships) as an executive and/or officer of the Company or an Affiliate immediately prior to the date of the Change in Control, or a material reduction or alteration in the nature or status of the Executive’s authorities, duties, or responsibilities from those in effect immediately prior to the date of the Change in Control, (including as a type of such reduction or alteration for an Executive who is an officer of a publicly traded company immediately prior to the date of the Change in Control, the Executive occupying the same position or title but with a company whose stock is not publicly traded), unless such act is remedied by the Company or such Affiliate within 10 business days after receipt of written notice thereof given by the Executive; or

(b)           A reduction by the Company or an Affiliate of the Executive’s base salary in effect immediately prior to the date of the Change in Control or as the same shall be increased from time to time, unless such reduction is less than ten percent (10%) and it is either (i) replaced by an incentive opportunity equal in value; or is (ii) consistent and proportional with an overall reduction in management compensation due to extraordinary business conditions, including but not limited to reduced profitability and other financial stress (i.e., the base salary of the Executive will not be singled out for reduction in a manner inconsistent with a reduction imposed on other executives of the Company or such Affiliate); or

(c)           The relocation of the Executive’s office more than 50 miles from the Executive’s office immediately prior to the date of the Change in Control; or

(d)           Failure of the Company or an Affiliate (whichever is the Executive’s employer) to provide (i) the Executive the opportunity to participate in all applicable incentive, savings and retirement plans, practices, policies and programs of the Company or such Affiliate to the same extent as other senior executives (or, where applicable, retired senior executives) of the Company or such Affiliate, and (ii) the Executive and/or the Executive’s family, as the case may be, the opportunity to participate in, and receive all benefits under, all applicable welfare benefit plans, practices, policies and programs provided by the Company or such Affiliate, including, without limitation, medical, prescription, dental, disability, sick benefits, accidental death and travel insurance plans and programs, to the same extent as other senior executives (or, where applicable, retired senior executives) of the Company or such Affiliate; or

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(e)           Failure of the Company or an Affiliate (whichever is the Executive’s employer) to provide the Executive such perquisites as the Company or such Affiliate may establish from time to time which are commensurate with the Executive’s position and at least comparable to those received by other senior executives at the Company or such Affiliate; or

(f)            The failure by the Company to comply with paragraph (c) of Section 11 of this Agreement; or

(g)           Any other substantial breach of this Agreement by the Company that either is not taken in good faith or is not remedied by the Company promptly after receipt of notice thereof from the Executive.

The Executive’s right to terminate employment for Good Reason shall not be affected by the Executive’s incapacity due to physical or mental illness.  The Executive’s continued employment shall not constitute consent to, or a waiver of rights with respect to, any circumstance constituting Good Reason herein.  A termination of employment by the Executive for Good Reason for purposes of this Agreement shall be effectuated by giving the Company written notice (“Notice of Termination for Good Reason”) of the termination within six (6) months of the occurrence of the event constituting Good Reason or, if such event is not immediately recognizable by the Executive, within six (6) months of the date the Executive became or reasonably should have become aware of such event, setting forth in reasonable detail the specific conduct of the Company that constitutes Good Reason and the specific provision(s) of this Agreement on which the Executive relies.  A termination of employment by the Executive for Good Reason shall be effective on the thirtieth (30^th) day following the date when the Notice of Termination for Good Reason is given, unless the notice sets forth a later date (which date shall in no event be later than sixty (60) days after the notice is given); provided, however, that no event described hereunder shall constitute Good Reason if such event is a result of an isolated, insubstantial and inadvertent action that is not taken in bad faith and that is remedied by the Company within five (5) days after receipt of the Notice of Termination for Good Reason by the Company from the Executive.  If the Company disputes the existence of Good Reason, the burden of proof is on the Company to establish that Good Reason does not exist.

1.7           Cause.  Cause shall mean the occurrence of any one or more of the following:

(a)           The Executive is convicted of a felony involving moral turpitude; or

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(b)           The Executive engages in conduct or activities that constitutes disloyalty to the Company or an Affiliate and such conduct or activities are materially damaging to the property, business or reputation of the Company or an Affiliate; or

(c)           The Executive persistently fails or refuses to comply with any written direction of an authorized representative of the Company other than a directive constituting an assignment described in Section 1.6(a); or

(d)           The Executive embezzles or knowingly, and with intent, misappropriates property of the Company or an Affiliate, or unlawfully appropriates any corporate opportunity of the Company or an Affiliate.

A termination of the Executive’s employment for Cause for purposes of this Agreement shall be effected in accordance with the following procedures.  The Company shall give the Executive written notice (“Notice of Termination for Cause”) of its intention to terminate the Executive’s employment for Cause, setting forth in reasonable detail the specific conduct of the Executive that it considers to constitute Cause and the specific provision(s) of this Agreement on which it relies, and stating the date, time and place of the Board Meeting for Cause.  The “Board Meeting for Cause” means a meeting of the Board at which the Executive’s termination for Cause will be considered, that takes place not less than ten (10) and not more than twenty (20) business days after the Executive receives the Notice of Termination for Cause.  The Executive shall be given an opportunity, together with counsel, to be heard at the Board Meeting for Cause.  The Executive’s Termination for Cause shall be effective when and if a resolution is duly adopted at the Board Meeting for Cause by a two-thirds vote of the entire membership of the Board, excluding employee directors, stating that in the good faith opinion of the Board, the Executive is guilty of the conduct described in the Notice of Termination for Cause, and that conduct constitutes Cause under this Agreement.

1.8           Annual Award Amount.  The average of the two highest annual incentive awards under the Company’s annual incentive plan (or the annual cash incentive plan maintained by a successor company or an Affiliate) paid in the last five years to the Executive prior to the occurrence of the Qualifying Termination; provided, however, that if the Executive has not been employed by the Company or an Affiliate for a sufficient length of time to have been eligible for payment of at least two annual incentive awards, deemed target award payout shall be used for the one or two years for which the Executive was not so eligible.

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1.9.          Affiliate.  The term “Affiliate” means any company directly or indirectly controlling, controlled by or under common control with the Company or any successor company.

2.             Severance Benefits for an Executive Ineligible to Retire.  Upon the occurrence of a Qualifying Termination with respectto an Executive who is Ineligible to Retire:

(a)           Severance Payment. The Company shall pay to the Executive an amount equal to three times the Executive’s annual base salary (asin effect on the date of the Qualifying Termination, not reduced by any reduction described in Section 1.6(b) above) and Annual Award Amount.  The payment shall be made in a lump sum after the Qualifying Termination, and within approximately 10 business days after the Company receives the executed agreement referred to in 2(f) below but in no case prior to the expiration of any period during which the Executive is permitted to revoke such agreement.

(b)           Supplemental Retirement Benefits.  For purposes of determining the Executive’s supplemental retirement benefits which the Executive is entitled to under the Company’s supplemental non-qualified retirement plan in which the Executive participated immediately prior to the Qualifying Termination (or the supplemental retirement plan maintained by a successor company or an Affiliate), (i) the Executive’s age shall be deemed equal to the greater of (A) age 55 or (B) the Executive’s actual age, (ii) the Executive’s service percentage shall be computed by adding three years of executive-level service to the Executive’s actual service, and (iii) any minimum service eligibility requirements for such benefits shall be waived.

(c)           Severance Health Benefits.  The Company shall provide to the Executive the substantially equivalent value of the medical and dental benefits provided to active employees for three years after the Qualifying Termination and thereafter to any retiree of the Company or a successor or an Affiliate (whichever is the Executive’s employer) who has attained the deemed age and service used to compute supplemental retirement benefits in Section 2(b) above.

(d)           Split Dollar.  The Qualifying Termination shall not constitute a termination of any Split Dollar Agreement between the Company and the Executive (or the split dollar agreement between a successor company or an Affiliate and the Executive), and the Executive shall be deemed to have retired upon such Qualifying Termination for purposes of such Split Dollar Agreement (or the split dollar agreement between a successor company or an Affiliate and the Executive).

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(e)           Outplacement.  For a 60-day period commencing on the date of the Qualifying Termination, the Executive is entitled to receive outplacement services from one or more organizations that are offered by the Company from time to time, with such services capped at a Company cost of $50,000.

(f)            Release.  The benefits described in this Section 2 are payable by the Company to the Executive only if after the date of the Qualifying Termination, the Executive executes (and does not subsequently revoke) in writing and submits to the Company, in the form, manner, and subject to the timing established by the Company, an agreement releasing legal claims, including those against the Company and its Affiliates, including but not limited to claims arising out of the Executive’s Company or Affiliate employment or termination of such employment.

3.             Severance Benefits for an Executive Eligible to Retire.  Upon the occurrence of a Qualifying Termination with respect to an Executive who is Eligible to Retire:

(a)           Severance Payment. The Company shall pay to the Executive an amount equal to three times the Executive’s annual base salary (as in effect on the date of the Qualifying Termination, not reduced by any reduction described in Section 1.6(b) above) and Annual Award Amount.  The payment shall be made in a lump sum after the Qualifying Termination, and within approximately 10 business days after the Company receives the executed agreement referred to in 3(f) below but in no case prior to the expiration of any period during which the Executive is permitted to revoke such agreement.

(b)           Supplemental Retirement Benefits.  For purposes of determining the Executive’s supplemental retirement benefits which the Executive is entitled to under the Company’s supplemental non-qualified retirement plan in which the Executive participated immediately prior to the Qualifying Termination (or the supplemental retirement plan maintained by a successor company or an Affiliate), the Executive’s supplemental retirement benefit shall not be reduced for early receipt.

(c)           Severance Health Benefits.  The Company shall provide to the Executive the substantially equivalent value of the medical and dental benefits provided to active employees for three years after the Qualifying Termination and thereafter to any retiree of the Company or a successor company or an Affiliate (whichever is the Executive’s employer) who has attained age 65 and completed the greater of 20 years or actual years of service.

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(d)           Retirement.  The Executive shall be treated as having retired at the Company’s request for purposes of all of the Company’s benefit plans (or the benefit plans maintained by a successor company or an Affiliate (whichever is the Executive’s employer)).

(e)           Outplacement.  For a 60-day period commencing on the date of the Qualifying Termination, the Executive is entitled to receive outplacement services from one or more organizations that are offered by the Company from time to time, with such services capped at a Company cost of $50,000.

(f)            Release.  The benefits described in this Section 3 are payable by the Company to the Executive only if after the date of the Qualifying Termination, the Executive executes (and does not subsequently revoke) in writing and submits to the Company, in the form, manner, and subject to the timing established by the Company, an agreement releasing legal claims, including those against the Company and its Affiliates, including but not limited to claims arising out of the Executive’s Company or Affiliate employment or termination of such employment.

4.             Non-Exclusivity of Rights.  Nothing in this Agreement shall prevent or limit the Executive’s continuing or future participation in any plan, program, policy or practice provided by the Company or a successor company or an Affiliate (whichever is the Executive’s employer) for which the Executive may qualify, nor shall anything in this Agreement limit or otherwise affect such rights as the Executive may have under any contract or agreement with the Company or a successor Company or such Affiliate.  However, if the Executive receives severance benefits under this Agreement, the Executive is not also entitled to any benefit under any other severance plan, program, arrangement or agreement maintained by the Company or an Affiliate.  Vested benefits and other amounts that the Executive is otherwise entitled to receive under any incentive compensation (including, but not limited to any restricted stock or stock option agreements), deferred compensation and other benefit programs listed in Section 1.6(d), life insurance coverage, or any other plan, policy, practice or program of, or any contract or agreement with, the Company or a successor Company or such Affiliate on or after the date of the Qualifying Termination shall be payable in accordance with the terms of each such plan, policy, practice, program, contract or agreement, as the case may be, except as explicitly modified by this Agreement.

5.             Full Settlement.  The Company’s obligation to make the payments provided for in, and otherwise to perform its obligations under, this Agreement shall not be affected by any set-off, counterclaim, recoupment, defense or other claim, right

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or action that the Company may have against the Executive or others.  In no event shall the Executive be obligated to seek other employment or take any other action by way of mitigation of the amounts payable to the Executive under any of the provisions of this Agreement and, such amounts shall not be reduced, regardless of whether the Executive obtains other employment.

6.             Certain Additional Payments by the Company.

(a)           Anything in this Agreement to the contrary notwithstanding, in the event it shall be determined that any payment or distribution by the Company to or for the benefit of the Executive (a “Payment”) would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code of 1986, as amended (the “Code”) or any interest or penalties are incurred by the Executive with respect to such excise tax (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the “Excise Tax”), then the Executive shall be entitled to receive an additional payment (a “Gross-Up Payment”) in an amount such that after payment by the Executive of all taxes (including any interest or penalties imposed with respect to such taxes), including, without limitation, any income taxes (and any interest and penalties imposed with respect thereon) and Excise Tax imposed upon the Gross-Up Payment, the Executive retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Payments.

(b)           Subject to the provisions of paragraph (c) of this Section 6, all determinations required to be made under this Section 6, including whether and when a Gross-Up Payment is required and the amount of such Gross-Up Payment and the assumptions to be utilized in arriving at such determination, shall be made by one of the major internationally recognized certified public accounting firms (commonly referred to, as of the date hereof, as a Big Five firm) designated by the Executive and approved by the Company (which approval shall not be unreasonably withheld) (the “Accounting Firm”), which shall provide detailed supporting calculations both to the Company and the Executive within fifteen (15) business days of the receipt of notice from the Executive that there has been a Payment, or such earlier time as is requested by the Company.  In the event that the Accounting Firm is serving as accountant or auditor for the individual, entity or group affecting the change of control, the Executive shall designate another Big Five accounting firm (subject to the approval of the Company, which approval shall not be unreasonably withheld) to make the determinations required hereunder (which accounting firm shall then be referred to as the Accounting Firm hereunder).  All fees and expenses of the Accounting Firm shall be borne solely by the Company.  Any Gross-Up Payment, as determined pursuant to this Section 6, shall be

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paid by the Company to the Executive within five (5) days of the receipt of the Accounting Firm’s determination.  Any determination by the Accounting Firm shall be binding upon the Company and the Executive.  As a result of the uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Accounting Firm hereunder, it is possible that Gross-Up Payments which will not have been made by the Company should have been made (“Underpayment”) consistent with the calculations required to be made hereunder.  In the event that the Company exhausts its remedies pursuant to paragraph (c) of this Section 6 and the Executive thereafter is required to make a payment of any Excise Tax, the Accounting Firm shall determine the amount of the Underpayment that has occurred and any such Underpayment shall be promptly paid by the Company to or for the benefit of the Executive.

(c)           The Executive shall notify the Company in writing of any claim by the Internal Revenue Service that, if successful, would require the payment by the Company of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later than ten (10) business days after the Executive is informed in writing of such claim and shall apprise the Company of the nature of such claim and the date on which such claim is requested to be paid.  The Executive shall not pay such claim prior to the expiration of the thirty (30) day period following the date on which the Executive gives such notice to the Company (or such shorter period ending on the date that any payment of taxes with respect to such claim is due).  If the Company notifies the Executive in writing prior to the expiration of such period that it desires to contest such claim, the Executive shall:

(i)            give the Company any information reasonably requested by the Company relating to such claim,

(ii)           take such action in connection with contesting such claim as the Company shall reasonably request in writing from time to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company,

(iii)          cooperate with the Company in good faith in order effectively to contest such claim, and

(iv)          permit the Company to participate in any proceedings relating to such claim;

PROVIDED, however, that the Company shall bear and pay directly all costs and expenses (including additional interest and penalties) incurred in connection with such contest and shall

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indemnify and hold the Executive harmless, on an after-tax basis, for any Excise Tax or income tax (including interest and penalties with respect thereto) imposed as a result of such representation and payment of costs and expenses.  Without limitation on the foregoing provisions of this paragraph (c) of Section 6, the Company shall control all proceedings taken in connection with such contest and, at its sole option, may pursue or forego any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct the Executive to pay the tax claimed and sue for a refund or contest the claim in any permissible manner, and the Executive agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company shall determine; PROVIDED, however, that if the Company directs the Executive to pay such claim and sue for a refund, the Company shall advance the amount of such payment to the Executive, on an interest-free basis and shall indemnify and hold the Executive harmless, on an after-tax basis, from any Excise Tax or income tax (including interest or penalties with respect thereto) imposed with respect to such advance or with respect to any imputed income with respect to such advance; and PROVIDED, further, that any extension of the statute of limitations relating to payment of taxes for the taxable year of the Executive with respect to which such contested amount is claimed to be due is limited solely to such contested amount.  Furthermore, the Company’s control of the contest shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Executive shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority.

(d)           If, after the receipt by the Executive of an amount advanced by the Company pursuant to paragraph (c) of this Section 6, the Executive becomes entitled to receive any refund with respect to such claim, the Executive shall promptly take all necessary action to obtain such refund and (subject to the Company’s complying with the requirements of paragraph (c) of this Section 6) upon receipt of such refund shall promptly pay to the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto).  If after the receipt by the Executive of an amount advanced by the Company pursuant to paragraph (c) of this Section 6, a determination is made that the Executive shall not be entitled to any refund with respect to such claim and the Company does not notify the Executive in writing of its intent to contest such denial of refund prior to the expiration of thirty (30) days after such determination, then such advance

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shall be forgiven and shall not be required to be repaid and the amount of such advance shall offset, to the extent thereof, the amount of Gross-Up Payment required to be paid.

7.             Termination of Agreement.  This Agreement shall remain in effect from the date hereof until the last day of the twenty-fourth calendar month following the date of a Change in Control.  Further, upon the date of a Change in Control, this Agreement shall continue until the Company or its successor shall have fully performed all of its obligations there under with respect to the Executive, with no future performance being possible.  Notwithstanding the foregoing, this Agreement may be terminated by the Board at any time prior to the date of a Change in Control.

8.             Amendment of Agreement.  This Agreement may be amended by the Board at any time prior to the date of a Change in Control.  At and after the date of a Change in Control, this Agreement may not be amended in any respect without the written consent of the Executive.

9.             Construction.  Wherever any words are used herein in the masculine gender they shall be construed as though they were also used in the feminine gender in all cases where they would so apply, and wherever any words are used herein in the singular form, they shall be construed as though they were also used in the plural form in all cases where they would so apply.

10.           Governing Law.  This Agreement shall be governed by the laws of Maryland.

11.           Successors and Assigns.

(a)           This Agreement shall inure to the benefit of and be enforceable by the Executive’s legal representatives.

(b)           This Agreement shall inure to the benefit of and be binding upon the Company and its successors and assigns.

(c)           The Company shall require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company expressly to assume and agree to perform this Agreement in the same manner and to the same extent that the Company would have been required to perform it if no such succession had taken place.  As used in this Agreement, “Company” shall mean both the Company as defined above and any such successor that assumes and agrees to perform this Agreement, by operation of law or otherwise.

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12.           Indemnification.  The Company will pay all reasonable fees and expenses, if any, (including, without limitation, legal fees and expenses) that are incurred by the Executive to enforce this Agreement and that result from a breach of this Agreement by the Company.

13.           Notice.  Any notices, requests, demands, or other communications provided for by this Agreement shall be sufficient if in writing and if sent by registered or certified mail to the Executive at the last address the Executive has filed in writing with the Company, or in the case of the Company, to its principal offices.

14.           Severability.  The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement.  If any provision of this Agreement shall be held invalid or unenforceable in part, the remaining portion of such provision, together with all other provisions of this Agreement, shall remain valid and enforceable and continue in full force and effect to the fullest extent consistent with law.

15.           Withholding.  Notwithstanding any other provision of this Agreement, the Company may withhold from amounts payable under this Agreement all federal, state, local and foreign taxes that are required to be withheld by applicable laws or regulations.

16.           Entire Agreement.  Unless otherwise specifically provided in this Agreement, the Executive and the Company acknowledge that this Agreement supersedes any other agreement between them or between the Executive and the Company or an Affiliate, concerning the subject matter hereof.

17.           Alienability.  The rights and benefits of the Executive under this Agreement may not be anticipated, alienated or subject to attachment, garnishment, levy, execution or other legal or equitable process except as required by law.  Any attempt by the Executive to anticipate, alienate, assign, sell, transfer, pledge, encumber or charge the same shall be void.  Payments hereunder shall not be considered assets of the Executive in the event of insolvency or bankruptcy.

18.           Counterparts.  This Agreement may be executed in several counterparts, each of which shall be deemed an original, and said counterparts shall constitute but one and the same instrument.

IN WITNESS WHEREOF, the Executive has hereunto set the Executive’s hand and, pursuant to the authorization of the Board,

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the Company has caused this Agreement to be executed in its name on its behalf, all as of the day and year first above written.

CONSTELLATION ENERGY GROUP, INC.

By:

[                       ]

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EX-10.(M)

Exhibit 10 (m)

CONSTELLATION ENERGY GROUP, INC.

BENEFITS RESTORATION PLAN

1.Objective.  The objective of this Plan is to restore the benefits provided to employees of Constellation Energy Group and its subsidiaries whose Pension Plan benefits are affected by Internal Revenue Code Limitations.

2.Definitions.  All words beginning with an initial capital letter and not otherwise defined herein shall have the meaning set forth in the Pension Plan.   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:

“Chairman” means the Chairman of the Board of Directors of Constellation Energy Group.

“Committee” means the Committee on Management of the Board of Directors of Constellation Energy Group.

“Constellation Energy Group” means Constellation Energy Group, Inc., a Maryland corporation, or its successor.

“Internal Revenue Code Limitations” means the limitations under Sections 415 and/or 401(a)(17) of the Internal Revenue Code.

“Nonqualified Deferred Compensation Plan” means the Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan.

“Pension Plan” means the Pension Plan of Constellation Energy Group, Inc. as may be amended from time to time, or any successor plan.

“Plan” means the Constellation Energy Group, Inc. Benefits Restoration Plan.

“Plan Administrator” means, as set forth in Section 3, the Vice President — Human Resources of Constellation Energy Group.

3.Plan Administration.  The Vice President — Human Resources of Constellation Energy Group is the Plan Administrator and

has sole authority (except as specified otherwise herein) to interpret the Plan and, in general, to make all other determinations advisable for the administration of the Plan to achieve its stated objective.  Appeals of written decisions by the Plan Administrator may be made to the Chairman.  Decisions by the Chairman shall be final and not subject to further appeal.  The Plan Administrator shall have the power to delegate all or any part of his/her duties to one or more designees, and to withdraw such authority, by written designation.

4.Eligibility.  Each employee of Constellation Energy Group or its subsidiaries whose Pension Plan benefits are reduced because of Internal Revenue Code Limitations, is a participant; provided, however that any such employee entitled to benefits payout under a plan listed in Appendix A is not a participant in this Plan; and provided further that employees or classifications of employees, designated by the Chairman or if required by Constellation Energy Group’s corporate charter or by-laws, the Committee, and reflected in Appendix B are also not participants in this Plan.

5.Restoration Benefits.

(a)Computation of benefits.  A participant’s (or if applicable, Surviving Spouse’s or Alternate Beneficiary’s) benefits under this Plan will be calculated as set forth below:

(i)Without regard to Internal Revenue Code Limitations, but subject to any compensation limitations, established by the Chairman or if required by Constellation Energy Group’s corporate charter or by-laws, the Committee, shown in Appendix C, compute the participant’s Gross Pension under the Pension Plan based on the participant’s Severance from Service Date and assuming that benefit payments commence on the first of the month following the Severance From Service Date; provided, however, that if the participant is not eligible to have payments start under the Pension Plan as of such date, benefit payments will be assumed to commence on the

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participant’s Normal Retirement Date in the form of a single life annuity; and

Subtract from the above amount the participant’s Gross Pension amount under the Pension Plan using the same Benefit Commencement Date.

(ii)Or, if a participant dies before his/her Benefits Commencement Date, compute without regard to Internal Revenue Code Limitations but subject to any compensation limitations established by the Chairman or if required by Constellation Energy Group’s corporate charter or by-laws, the Committee, shown in Appendix C, the participant’s Surviving Spouse’s or Alternate Beneficiary’s benefit under the Pension Plan based on payments commencing on the first of the month following the participant’s date of death; and

Subtract from the above amount the amount payable to the Surviving Spouse or Alternate Beneficiary under the Pension Plan based on payments commencing on the first of the month following the participant’s date of death.

(b)Form of payout of benefits — generally.  For a participant, the payout under this Plan will be a monthly payment, unless the participant makes a valid election to receive his/her payout in the form of a lump sum; however, if the present value of the participant’s Plan payout is under $50,000, it will be paid automatically in the form of a lump sum.  Such automatic lump sum is not eligible for rollover to the Nonqualified Deferred Compensation Plan.  For this purpose, the present value of the Plan payout will be the amount that would be payable to a participant under paragraph (d) if he or she elected to receive a lump sum.

A participant may elect to receive his/her payout in the form of a lump sum by submitting to the Plan Administrator a signed Lump Sum Election Form.  On such Form, the participant may elect to rollover such payout directly to the Nonqualified Deferred Compensation Plan, provided such participant is otherwise eligible to participate in the Nonqualified Deferred Compensation Plan.  The Form must be received by the

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Plan Administrator before the beginning of the calendar year during which the participant’s Severance From Service Date occurs.  The election to receive a payout in the form of a lump sum, or to rollover such payment to the Nonqualified Deferred Compensation Plan, may be revoked at any time before the beginning of the calendar year during which the participant’s Severance From Service Date occurs, by submitting to the Plan Administrator a signed Lump Sum Revocation Form.

(c)Amount and timing, of participant monthly benefits payout.  A participant entitled to monthly benefits payouts will receive monthly payments based on the amount determined under paragraph (a); provided, however, that if such amount is determined as of the participant’s Normal Retirement Date, it will be multiplied by the applicable factor determined in Appendix E (Early Receipt Reduction Factors) of the Pension Plan.  Such payments shall be paid in the form of a single life annuity, unless the participant elects as set forth in paragraph (b) to receive such payments in the form of a joint and survivor annuity, and the annuity payment shall be reduced by the applicable factor determined in Appendix F (Contingent Annuitant Reduction Factors) of the Pension Plan.  Payments under this paragraph (c) shall commence effective with the first day of the month following the participant’s Severance From Service Date.  If such participant receives (or would have received but for the Internal Revenue Code limitations) cost of living adjustment(s) under the Pension Plan, the monthly payments hereunder will be automatically increased based on the percentage of, and at the same time as, such adjustment(s).

Monthly payments to the participant hereunder shall permanently cease upon the death of the participant, effective with the monthly payment for the month following the month of the participant’s death.

(d)Amount and timing of participant lump sum benefits payout.  A participant entitled to a lump sum benefit payout will receive a lump sum payment based on the same assumptions and procedures that are used for determining lump sums in the Pension Plan. Such lump sum payment shall be made within 60 days after the participant’s Severance From Service Date, and shall either be paid to the participant, or rolled over to

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the Nonqualified Deferred Compensation Plan pursuant to the participant’s election under (b).

(e)Amount and timing of Surviving Spouse or Alternate Beneficiary payout.

Before Benefit Commencement Date:  A Surviving Spouse or Alternate Beneficiary who is entitled to a Preretirement Survivor Annuity or a Preretirement Survivor Benefit under the Pension Plan shall receive a benefit payment under this Plan in the form of a lump sum, and equal to an amount determined under paragraph (a) and payable within 60 days after the participant’s death.

After Benefit Commencement Date:  A participant who is entitled to begin receipt of monthly benefits payments under paragraph (c) of this Plan, may elect to provide a survivor benefit to his/her Surviving Spouse or Alternate Beneficiary (whichever is applicable) in the form of a joint and survivor annuity, the calculation of which is set forth in the Pension Plan.  Payments to either a Surviving Spouse or an Alternate Beneficiary under this Plan shall begin the first day of the month following the participant’s death. If the named Surviving Spouse or Alternate Beneficiary predeceases the participant, no survivor benefits are payable upon the participant’s death.

If a participant elects survivor coverage for the monthly benefit payments under this Plan, the participant must provide all appropriate survivor benefit information in the timing and manner established by the Plan Administrator, before commencing benefit payments under paragraph (c) of this Plan.

(f)Death of participant entitled to lump sum payout.  In the event of the death of a participant after his/her Severance From Service Date and before the participant receives or rolls over the lump sum payment under paragraph (d), such lump sum payment shall be made to the participant’s Alternate Beneficiary; and if there is no Alternate Beneficiary to the Surviving Spouse; and if there is no Surviving Spouse to the participant’s beneficiary under the employer’s employee life insurance plan; and if there is no beneficiary

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under the employer’s employee life insurance plan, to the participant’s estate.  In the event of the death of a Surviving Spouse or Alternate Beneficiary after the participant’s death and before the Surviving Spouse or Alternate Beneficiary receives the lump sum payment under paragraph (e), such lump sum payment shall be made to the estate of the Surviving Spouse or Alternate Beneficiary (whichever is applicable.)   The lump sum payment shall be the same amount and made at the same time as set forth in paragraphs (d) and (e).

(g)Source of Payments.  All payments under this Plan shall be made from the general corporate assets of Constellation Energy Group.

6.Miscellaneous.  None of the benefits provided under this Plan shall be subject to alienation or assignment by any participant or beneficiary nor shall any of them be subject to attachment or garnishment or other legal process except (i) to the extent specially mandated and directed by applicable State or Federal law; or (ii) as requested by the participant or beneficiary to satisfy income tax withholding or liability.

This Plan may be amended from time to time, or suspended or terminated at any time, provided, however, that no amendment or termination shall impair the rights of any participant or beneficiary entitled to receive current or future payment hereunder at the time of such action.  All amendments to this Plan which would increase or decrease the compensation of any Officer of Constellation Energy Group, either directly or indirectly, must be approved by the Constellation Energy Group Board of Directors.  All other permissible amendments may be made at the written direction of the Plan Administrator.

Participation in this Plan shall not constitute a contract of employment between Constellation Energy Group or a subsidiary of Constellation Energy Group and any person and shall not be deemed to be consideration for, or a condition of, continued employment of any person.

The Plan is intended to be unfunded for purposes of Title I of the Employee Retirement Income Security Act of 1974.  To the extent that any person acquires a right to receive payments from Constellation Energy Group under this Plan,

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such rights shall be no greater than the right of any unsecured general creditor of Constellation Energy Group.

In the event Constellation Energy Group becomes a party to a merger, consolidation, sale of substantially all of its assets or any other corporate reorganization in which Constellation Energy Group will not be the surviving corporation or in which the holders of the common stock of Constellation Energy Group will receive securities of another corporation (in any such case, the “New Company”), then the New Company shall assume the rights and obligations of Constellation Energy Group under this Plan.

This Plan shall be governed in all respects by Maryland law.

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APPENDIX A

Participants entitled to a benefit payout under the following Constellation Energy Group plans are not participants in this Plan:

1.Senior Executive Supplemental Plan

2.Supplemental Pension Plan

3.Senior Management Pension Plan

4.Senior Management Supplemental Pension Plan

APPENDIX  B

Pursuant to Section 4 of the Plan, the following employees or classification of employees are ineligible to participate in this Plan:

None

APPENDIX  C

Pursuant to Section 5(a)(i) of the Plan, compensation used to calculate benefits under this Plan is limited as follows:

For participants employed by Constellation Power Source, Inc. as marketers, traders or strategists, the bonus and incentive portion of a participant’s Final Average Pay or Average Annual Pay will be limited to a maximum of $200,000 per calendar year.

Amendments to the Constellation Energy Group, Inc.

Benefits Restoration Plan (Plan)

Notwithstanding anything in Section 5(b) of the Plan to the contrary, any participant who terminates employment in connection with the management restructuring announced late in 2001, and who wants to receive a lump sum payout of his/her Plan benefit in 2002, must irrevocably elect by December 31, 2001 to rollover the present value of his/her accrued benefit under the Plan to the Nonqualified Deferred Compensation Plan effective December 31, 2001.  Any additional benefit accruals under the Plan during 2002 and prior to employment termination will automatically be paid in a lump sum from the Plan within 60 days after employment termination.

EX-10.(N)

Exhibit 10 (n)

CONSTELLATION ENERGY GROUP, INC.

SUPPLEMENTAL PENSION PLAN

1.             Objective.  The objective of this Plan is to enhance the benefits provided to certain officers and key employees of  Constellation Energy Group and its subsidiaries in order to attract and retain talented executive personnel.

2.             Definitions.  All words beginning with an initial capital letter and not otherwise defined herein shall have the meaning set forth in the Pension Plan.  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:

“Annual Base Salary” means an amount determined by adding the monthly base rate of pay amounts (i.e., the types of such pay that are includable in the computation of Pension Plan benefits)earned over the twelve calendar months immediately preceding the month that includes the date of the computation.

“Average Incentive Award” (or “Average Award”) means generally the product of the percentage equal to an average of the two highest of the participant’s five immediately prior year award percentages earned under Constellation Energy Group’s Executive Annual Incentive Plan, Constellation Energy Group’s Senior Management Annual Incentive Plan and/or other Incentive Awards Program multiplied by the participant’s annualized base rate of pay amount (i.e., the types of such pay that are includable in the computation of Pension Plan benefits) in effect at the end of the prior year.

“Benefit Start Date” means the date as of which the participant’s benefits, if any, under this Plan commence.

“Cause” means the participant’s (a) failure to comply with Constellation Energy Group policy, (b) deliberate and continual refusal to satisfactorily perform employment duties on substantially a full-time basis, (c) deliberate and continual refusal to act in accordance with any specific instructions of a majority of Constellation Energy Group’s Board of Directors, (d) disclosure, without the consent of a majority of Constellation Energy Group’s Board of Directors,

of confidential information or trade secrets concerning Constellation Energy Group which could be materially damaging to Constellation Energy Group, or (e) deliberate misconduct which could be materially damaging to Constellation Energy Group without reasonable good faith belief by the participant that such conduct was in the best interest of Constellation Energy Group.

“Change in Control” means (a) the purchase or acquisition by any person, entity or group of persons, (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), or any comparable successor provisions), of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20 percent or more of either the outstanding shares of common stock of Constellation Energy Group or the combined voting power of Constellation Energy Group’s then outstanding shares of voting securities entitled to a vote generally, or (b) the consummation of, following the approval by the stockholders of Constellation Energy Group of a reorganization, merger, or consolidation of Constellation Energy Group, in each case, with respect to which persons who were stockholders of Constellation Energy Group immediately prior to such reorganization, merger or consolidation do not, immediately thereafter, own more than 50 percent of the combined voting power entitled to vote generally in the election of directors of the reorganized, merged or consolidated entity’s then outstanding securities, or (c) a liquidation or dissolution of Constellation Energy Group or the sale of substantially all of its assets, or (d) a change of more than one-half of the members of the Board of Directors of Constellation Energy Group within a 90-day period for reasons other than the death, disability, or retirement of such members.

“Committee” means the Committee on Management of the Board of Directors of Constellation Energy Group.

“Constellation Energy Group” means Constellation Energy Group, Inc., a Maryland corporation, or its successor.

“Constellation Energy Group’s Executive Annual Incentive Plan” means such plan or other incentive plan or arrangement designated in writing by the Plan Administrator.

“Constellation Energy Group’s Senior Management Annual Incentive Plan” means such plan or other incentive plan or arrangement designated in writing by the Plan Administrator.

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“Demotion” means a transfer to a position with Constellation Energy Group or a subsidiary of Constellation Energy Group that either (a) is substantially below the position in which the participant was employed on the date of transfer, or (b) results in a substantial reduction in pay when compared to the participant’s pay on the date of the transfer.  Whether a position is a substantially below another position shall be determined in the reasonable discretion of the Committee, with reference to factors including whether the participant retains principal responsibility for a department or division, and whether the participant remains eligible for the perquisites enjoyed by the participant before the position change.

“Early Receipt Reduction Factor” means 100% less .25% for each month that the participant is less than age 62 on the participant’s Benefit Start Date.

“Interest Rate” means the rate equal to the average monthly 30–year Treasury bond rate for the second calendar quarter preceding the computation date, less 50 basis points.

“Internal Revenue Code Limitations” means the limitations under Sections 415 and/or 401(a)(17) of the Internal Revenue Code.

“LTD Plan” means the Constellation Energy Group, Inc. Disability Insurance Plan as may be amended from time to time, or any successor plan.

“Mortality Table” means the mortality table used to convert annuities to lump sums in the Pension Plan.

“Nonqualified Deferred Compensation Plan” means the Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan.

“Other Incentive Awards Program” means the program(s) designated in writing by the Plan Administrator applicable to certain employees that provides awards; but includes only the types of awards that are includable in the computation of Pension Plan benefits.

“Pension Plan” means the Pension Plan of Constellation Energy Group, Inc. as may be amended from time to time, or any successor plan.

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“Plan” means this Constellation Energy Group, Inc. Supplemental Pension Plan.

“Plan Administrator” means, as set forth in Section 3, the Committee.

“Rabbi Trust” means the trust adopted by Constellation Energy Group pursuant to the Grantor Trust Agreement Dated as of January 1, 2001, between Constellation Energy Group and Citibank, N.A.

“Survivor Annuity Percentage” means 50%, unless the participant elects in the timing and manner established by the Plan Administrator, a higher percentage (in multiples of 5% to a total percentage not to exceed 100%).

“Termination From Employment With Constellation Energy Group” means a participant’s separation from service with Constellation Energy Group or a subsidiary of Constellation Energy Group; however, a participant’s retirement, disability, or transfer of employment to or from a subsidiary of Constellation Energy Group shall not constitute a Termination From Employment With Constellation Energy Group.

3.             Plan Administration.  The Committee is the Plan Administrator and has sole authority (except as specified otherwise herein) to interpret the Plan and, in general, to make all other determinations advisable for the administration of the Plan to achieve its stated objective.  Appeals of written decisions by the Plan Administrator may be made to the Board of Directors of Constellation Energy Group.  Decisions by the Board shall be final and not subject to further appeal.  The Plan Administrator shall have the power to delegate all or any part of its duties to one or more designees, and to withdraw such authority, by written designation.

4.             Eligibility.  The officers or key employees of Constellation Energy Group or its subsidiaries designated in Appendix A are participants under the Plan.  Participation shall continue until such designation is withdrawn at the discretion and by written order of the Plan Administrator, provided, however, that such withdrawal may not be made for benefits provided pursuant to Sections 5 and 6 with respect to a participant who has satisfied the eligibility requirements to retire (as set forth in Section 5(b)(i)).  Notwithstanding the foregoing, any participant while

4

classified as disabled under the LTD Plan shall continue to participate in this Plan while classified as disabled and, for purposes of the supplemental pension benefit provided by this Plan, while classified as disabled, shall be deemed to continue to accrue Credited Service until no later than his/her Normal Retirement Date.

5.             Supplemental Pension Benefit.

(a)           Generally.  A participant shall be eligible for supplemental pension benefits and supplemental survivor annuity benefits under this Plan only if the participant’s supplemental pension benefits under this Plan are greater than the supplemental pension benefits computed under the Senior Executive Supplemental Plan based on the participant’s age, service, and eligible compensation on the date as of which benefits become payable.

(b)           Retirement benefits.

(i)            Eligibility for retirement benefits.  A participant shall be eligible to retire under this Plan on or after the participant’s Normal Retirement Date, or on the first day of any month preceding his/her Normal Retirement Date, if on his/her Severance From Service Date and while a participant he/she has attained (1) age 55 and has accumulated at least 10 years of Credited Service; or (2) age 60 and has accumulated at least one year of Credited Service.

(ii)           Computation of retirement benefits.  A participant who is eligible to retire under this Plan will be entitled to supplemental pension retirement benefits under this Plan, which will be calculated as set forth below on the participant’s Benefit Start Date:

(1)           add the Annual Base Salary and the Average Incentive Award,

(2)           divide the sum by 12,

(3)           multiply this dollar amount by the appropriate percentage, determined as follows:  Chairman of the Board of

5

Constellation Energy Group — 60%; all other participants (by completed years of Credited Service) 1 through 9 — 3% per year; 10 through 19 — 40%; 20 through 24 — 45%; 25 through 29 — 50%; and 30 or more — 55%,

(4)           multiply this dollar amount by the Early Receipt Reduction Factor; provided, however, if the participant is age 62 or older, such factor shall be one (1),

(5)           subtract from this dollar amount the charges relating to coverage for a preretirement survivor annuity in excess of 50%, and for a post-retirement survivor annuity in excess of 50%, and

(6)           subtract from the remainder the net amount payable to the participant under the Pension Planon the participant’s Benefit Start Date, assuming a 50% spousal joint and survivor annuity for a married participant(if the participant is not eligible to commence monthly Pension Plan payments on the participant’s Benefit Start Date, the participant’s benefit will be unreduced for Pension Plan payments until the date the participant is first eligible to commence monthly Pension Plan payments), or, if the participant elects a lump sum under the PEP provisions of the Pension Plan, the monthly amount that would have been payable under the Pension Plan as a life annuity for a single participant or as a 50% spousal joint and survivor annuity for a married participant, as of the Benefit Start Date under this Plan.

(iii)          Form of payout of retirement benefits.  Each participant entitled to supplemental pension retirement benefits will receive his/her supplemental pension retirement benefits payout in the form of a monthly payment, unless the participant makes a valid election to receive his/her supplemental pension retirement benefits payout in the form of a lump sum.

A participant may elect to receive his/her supplemental pension retirement benefits payout in

6

the form of a lump sum by submitting to the Plan Administrator a signed Lump Sum Election Form.  On such Form, the participant may elect to rollover such payout directly to the Nonqualified Deferred Compensation Plan.  The Form must be received by the Plan Administrator before the beginning of the calendar year during which the participant’s Severance From Service Date occurs.  The election to receive a payout in the form of a lump sum, or to rollover such payment to the Nonqualified Deferred Compensation Plan, may be revoked at any time before the beginning of the calendar year during which the participant’s Severance From Service Date occurs, by submitting to the Plan Administrator a signed Lump Sum Revocation Form.

(iv)          Amount, timing, and source of monthly retirement benefit payout.  A participant entitled to monthly supplemental pension retirement benefits will receive monthly payments equal to the amount determined under paragraph (b)(ii).  Such payments shall commence effective with the first of the month following the participant’s Severance From Service Date.  If such participant receives (or would have received but for the Internal Revenue Code Limitations) cost of living adjustment(s) under the Pension Plan, the monthly payments hereunder will be automatically increased based on the percentage of, and at the same time as, such adjustment(s).  Monthly payments hereunder shall permanently cease upon the death of the participant, effective with the monthly payment for the month following the month of the participant’s death.  Monthly payments hereunder shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets.

(v)           Amount, timing, and source of lump sum retirement benefit payout.  A participant entitled to a lump sum supplemental pension retirement benefit will receive a lump sum payment.  This lump sum payment will be calculated by a certified actuary and will be equal to the present value of an immediate annuity including the estimated present value of post-retirement supplemental survivor annuity

7

benefits described in Section 6, and reflecting the present value of any deferred Pension Plan payments using (1) the supplemental pension retirement benefit amount calculated under paragraph (b)(ii), which is expressed as a monthly amount, (2) the Interest Rate computed on the participant’s Benefit Start Date, and (3) the Mortality Table.  Such lump sum payment shall be made within 60 days after the participant’s Severance From Service Date, and shall either be paid to the participant, or rolled over to the Nonqualified Deferred Compensation Plan pursuant to the participant’s election under (b)(iii).  The lump sum payment shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets.  A participant who receives or rolls over a lump sum payment shall not be entitled to any cost of living or other pension payment adjustments or to post-retirement survivor annuity coverage under the Plan.

(vi)          Death of participant entitled to lump sum payout.  In the event of the death of a participant after his/her Severance From Service Date and before the participant receives or rolls over the lump sum payment under paragraph (b)(v), such lump sum payment shall be made to the participant’s surviving spouse (as defined in Section 6(i)).  The lump sum payment shall be the same amount and made at the same time and from the same sources as set forth in paragraph (b)(v).  If there is no surviving spouse at the date of the participant’s death, no payments shall be made pursuant to Sections 5 or 6.  A surviving spouse who receives a lump sum benefit under this paragraph (b)(vi) shall not be entitled to any cost of living or other pension payment adjustments or to post-retirement survivor annuity coverage under the Plan.

(c)                           Entitlement to benefit upon happening of certain events.

(i)            Computation of gross accrued benefit.  The computation of the gross accrued supplemental

8

pension benefit for a participant as of the date of the computation will be made as follows:

(1)           add the Annual Base Salary and the Average Incentive Award,

(2)           divide the sum by 12, and

(3)           multiply this dollar amount by the appropriate percentage, determined as follows:  Chairman of the Board of Constellation Energy Group — 60%; all other participants (by completed years of Credited Service as of the date of the computation) 1 through 9 — 3% per year; 10 through 19 — 40%; 20 through 24 — 45%; 25 through 29 — 50%; and 30 or more — 55%.

(ii)           Computation of net accrued benefit.  The computation of the net accrued supplemental pension benefit for a participant as of the date of the computation will be made by subtracting from the gross accrued benefit determined under paragraph (c)(i) the amount of the participant’s Gross Pension under the Pension Plan determined as of the date of the computation and assuming that monthly payments of such Gross Pension begin on the first of the month after the later of reaching age 62 or the date of the computation.  If the participant is not eligible for payment of a Gross Pension under the Pension Plan, the participant’s Accrued Gross Pension determined as of the date of the computation shall be substituted for the Gross Pension described above, with the appropriate reduction for early receipt applied as if the participant were eligible to begin payment of his Accrued Gross Pension on the first of the month after the later of reaching age 62 or the date of the computation.

(iii)          Satisfaction of requirements.  A participant who has satisfied the age and Credited Service requirements set forth in Section 5(b)(i) while eligible as set forth in Section 4, but who the Committee determines does not retire under the Plan due to Demotion, Termination From Employment With Constellation Energy Group, or the withdrawal of a participant’s eligibility to participate

9

under Section 5,  shall be entitled to his/her net accrued supplemental pension  benefit.  The effective date of the Demotion, Termination From Employment With Constellation Energy Group, or eligibility withdrawal event shall be the date of such Demotion, Termination From Employment With Constellation Energy Group, or eligibility withdrawal.

(iv)          Other events.  A participant, regardless of his/her age and years of Credited Service, shall be entitled to his/her net accrued supplemental pension benefit upon the happening of any of the following entitlement events, but only if such entitlement event occurs while a participant and before a participant retires under this Plan:

(1)           Change in Control.  A Change in Control, followed within two years by the participant’s Demotion, a participant’s Termination From Employment With Constellation Energy Group, or the withdrawal of the participant’s eligibility to participate under the Plan, is an entitlement event.  The effective date of the entitlement event shall be the date of the Demotion, Termination From Employment With Constellation Energy Group, or eligibility withdrawal.

(2)           Plan amendment.  A Plan amendment that has the effect of reducing a participant’s gross accrued supplemental pension benefit is an entitlement event.  In determining whether such a reduction has occurred, the participant’s gross accrued supplemental pension benefit calculated on the day immediately preceding the effective date of the amendment shall be compared to the participant’s gross accrued supplemental pension benefit calculated on the effective date of the amendment.  An amendment that has the effect of reducing future benefit accruals is not an entitlement event.  It is intended that an entitlement event under this paragraph (c)(iv)(2) will occur only with respect to those amendments that are substantially similar to amendments that are

10

prohibited by Internal Revenue Code section 411(d)(6) with respect to qualified pension plans.  The effective date of the entitlement event shall be the effective date of the Plan amendment.

(3)           Involuntary Demotion, Termination From Employment With Constellation Energy Group, or eligibility withdrawal without Cause.  A participant’s involuntary Demotion or involuntary Termination From Employment With Constellation Energy Group without Cause, or the withdrawal of a participant’s eligibility to participate under Sections 5 or 6 of the Plan without Cause, is an entitlement event.  The effective date of the entitlement event shall be the effective date of the participant’s involuntary Demotion or involuntary Termination From Employment With Constellation Energy Group without Cause, or the eligibility withdrawal without Cause.

(v)           Form of benefit payout.  Each participant entitled to a payout under this paragraph (c) will receive such payout in the form of a lump sum payment.

(vi)          Amount, timing, and source of benefit payout.  A participant entitled to a payout of his/her net accrued benefit, as a result of the occurrence of an event described in paragraphs (c)(iii), (c)(iv)(1), (2), or (3) will be entitled to a lump sum benefit.  This lump sum benefit will be calculated by a certified actuary as the present value, determined as of the date of payment, of an annuity beginning at age 62  (or the participant’s actual age, if the participant is older than age 62 on the date the lump sum benefit is payable), including the estimated present value of post-retirement survivor annuity benefits described in Section 7, using (1) the net accrued benefit amount calculated under paragraph (d)(ii) on the effective date of the entitlement event, which is expressed as a monthly amount, (2) the Interest Rate computed on the date the lump sum benefit is payable, and (3) the Mortality Table.  The lump sum benefit shall be payable as of the participant’s Severance From service Date, and

11

shall be made within 60 days after such date in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets.  A participant who receives a lump sum benefit under this paragraph (c)(vi) shall not be entitled to any cost of living or other pension payment adjustments or to preretirement or post-retirement survivor annuity coverage.

(vii)         Death of participant entitled to lump sum payout.  In the event of the death of a participant after the occurrence of an event described in paragraphs (c)(iii), (c)(iv)(1), (2), or (3) and before the participant receives the lump sum payment under paragraph (c)(v), such lump sum payment shall be made to the participant’s surviving spouse (as defined in Section 6(i)).  The lump sum payment will be calculated by a certified actuary and will be equal to 100% of the lump sum that would have been paid to the participant under paragraph (vi), as of the date on which the lump sum is payable under this paragraph (vii), provided that the participant’s date of death is on or after his/her Severance From Service Date.  If the participant’s date of death is before his/her Severance From Service Date, 50% shall be substituted for 100% in the preceding sentence. The lump sum benefit shall be payable as of the earlier of the participant’s Severance From Service Date or date of death, and shall be made within 60 days after such date in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets.  If there is no surviving spouse at the date of the participant’s death, no payments shall be made pursuant to Sections 5 or 6.  A surviving spouse who receives a lump sum benefit under this paragraph (c) (vii) shall not be entitled to any cost of living or other pension payment adjustments or to preretirement or post-retirement survivor annuity coverage under the Plan.

6.             Supplemental Survivor Annuity Benefit.

(a)           Survivor annuity benefit.

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(i)            Eligibility for survivor annuity benefit.  Following the death of a participant who is fully vested under the Pension Plan, a supplemental survivor annuity may be paid to the participant’s surviving spouse until the death of that spouse, using the Survivor Annuity Percentage.The participant will not bear the cost of up to a 50% survivor annuity benefit, but will bear the cost of a survivor annuity benefit in excess of 50%.  For purposes of this Section 6(a), a participant’s surviving spouse is the individual married to the participant on the date of the participant’s death.  If there is no surviving spouse, or if the participant or the participant’s spouse previously received or is entitled to receive either a lump sum payment under Section 5, or a benefit under the Senior Executive Supplemental Plan, no supplemental survivor annuity will be payable.

(ii)           Computation of survivor annuity benefit.  The amount of the supplemental survivor annuity will be determined as follows:

(1)           if the participant’s Benefit Start Date occurred prior to the date of death:

(a)           begin with the monthly pension benefit (under Section 5(b) of this Plan) that the participant was receiving prior to the date of death, and

(b)           multiply this dollar amount by the Survivor Annuity Percentage.

(2)           otherwise:

(a)           Unless the participant elected the alternative in-service death benefit in section (b) below:

(1)           begin with the monthly Early Retirement pension benefit (under both the Pension Plan and Section 5(b) of this Plan) to which the participant would have been entitled to receive if:

the participant had been retired at the later of age 60 or his/her

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actual age on the date of death for purposes of computing the Early Receipt Reduction Factor,

(2)           multiply this dollar amount by the Survivor Annuity Percentage,

(3)           subtract from the product the net amount, if any, of the survivor annuity provided on behalf of the participant under the Pension Plan if the participant is participating in the Traditional Pension Plan, or the monthly annuity that would have been provided to the participant’s spouse assuming that he or she had been designated as the participant’s beneficiary and had chosen to receive a survivor benefit in the form of a monthly annuity, if the participant is participating in the PEP, and

(4)           subtract from this dollar amount the charges relating to coverage (under both the Pension Plan and this Plan) for a preretirement survivor annuity in excess of 50%.

(b)           If the participant was a participant in the Pension Equity Plan option of the Pension Plan and elected this alternative in-service death benefit by December 31 of the year prior to his/her death or during the 2001 initial election period established by the Plan Administrator

(1)           calculate the benefit under the Constellation Energy Group Benefits Restoration Plan that would have been payable to the surviving spouse if the participant were a participant in that plan and

(2)           that dollar amount will be paid to the surviving spouse only in the form of a lump sum from this Plan.

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(iii)          Form of payout of survivor annuity benefits. Unless the participant made a valid election by December 31 of the year prior to his/her death or during the 2001 initial election period established by the Plan Administrator, to have the survivor benefits paid in a lump sum, each  surviving spouse entitled to a supplemental survivor annuity benefit will receive his/her survivor annuity benefit payout in the form of a monthly payment.

(iv)          Amount, timing, and source of monthly survivor annuity benefit payout.  A surviving spouse entitled to monthly supplemental survivor annuity benefits will receive a monthly payment equal to the amount determined under (ii) above.  Such payments shall commence effective with the first day of the month following the month of the participant’s death.  If such surviving spouse receives (or would have received but for the Internal Revenue Code Limitations) cost of living adjustment(s) under the Pension Plan, the monthly payments hereunder will be automatically increased based on the percentage of, and at the same time as, such adjustment(s).  Monthly payments hereunder shall permanently cease upon the death of the surviving spouse, effective with the monthly payment for the month following the month of the surviving spouse’s death.  Monthly payments hereunder shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets.

(v)           Amount, timing, and source of lump sum survivor benefit payout. A surviving spouse entitled to a lump sum supplemental survivor benefit will receive a lump sum payment.  This lump sum payment will be calculated by a certified actuary and will be equal to the present value of an immediate annuity. Such lump sum payment shall be made within 60 days after the participant’s death.  The lump sum payment shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets.  A surviving spouse who receives a lump sum payment shall not

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be entitled to any cost of living or other pension payment adjustments.

(vi)          Death of surviving spouse entitled to lump sum payout.  In the event of the death of a surviving spouse before the spouse receives the lump sum payment under section 6(a)(v) no payment shall be made.

7.             Miscellaneous.  None of the benefits provided under this Plan shall be subject to alienation or assignment by any participant or beneficiary nor shall any of them be subject to attachment or garnishment or other legal process except (i) to the extent specially mandated and directed by applicable State or Federal statute; or (ii) as requested by the participant or beneficiary to satisfy income tax withholding or liability.

This Plan may be amended from time to time, or suspended or terminated at any time, provided, however, that no amendment or termination shall reduce any previously accrued supplemental pension benefit under this Plan or impair the rights of any participant or beneficiary entitled to receive current or future payment hereunder at the time of such action.  All amendments to this Plan may be made at the written direction of the Committee. Notwithstanding anything else in this Plan to the contrary, the Constellation Energy Group Board of Directors may authorize a Participant to be eligible for benefits or may increase benefit payments.

Participation in this Plan shall not constitute a contract of employment between Constellation Energy Group or any of its subsidiaries and any person and shall not be deemed to be consideration for, or a condition of, continued employment of any person.

The Plan, notwithstanding the creation of the Rabbi Trust, is intended to be unfounded for purposes of Title I of the Employee Retirement Income Security Act of 1974. Constellation Energy Group shall make contributions to the Rabbi Trust in accordance with the terms of the Rabbi Trust.  Any funds which may be invested and any assets which may be held to provide benefits under this Plan shall continue for all purposes to be a part of the general funds and assets of Constellation Energy Group and no person other than Constellation Energy Group shall by virtue of the provisions of this Plan have any interest in such funds and assets.  To the extent that any person acquires a right to receive

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payments from Constellation Energy Group under this Plan, such rights shall be no greater than the right of any unsecured general creditor of Constellation Energy Group.

In the event Constellation Energy Group becomes a party to a merger, consolidation, sale of substantially all of its assets or any other corporate reorganization in which Constellation Energy Group will not be the surviving corporation or in which the holders of the common stock of Constellation Energy Group will receive securities of another corporation (in any such case, the “New Company”), then the New Company shall assume the rights and obligations of Constellation Energy Group under this Plan.

This Plan shall be governed in all respects by Maryland law.

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Amendments to the Constellation Energy Group, Inc.

Supplemental Pension Plan (Plan)

1.             Notwithstanding anything in Section 5(b)(iii) of the Plan to the contrary, any participant who terminates employment in connection with the management restructuring announced late in 2001, and who wants to receive a lump sum payout of his/her Plan benefit in 2002, must irrevocably elect by December 31, 2001 to rollover the present value of his/her accrued benefit under the Plan to the Nonqualified Deferred Compensation Plan effective December 31, 2001.  Any additional benefit accruals under the Plan during 2002 and prior to employment termination will automatically be paid in a lump sum from the Plan within 60 days after employment termination.

2.             Notwithstanding anything in Section 5(b)(ii) to the contrary, participants designated by the Plan Administrator who are at least age 55 with 10 or more years of service as of January 31, 2002 and who make an irrevocable election in the time and manner established by the Plan Administrator to voluntarily retire on February 1, 2002 (or such later date on or before July 1, 2002 as required in the sole discretion of management), is entitled to an enhanced early retirement benefit conditioned on such participants’ execution of a waiver releasing Constellation Energy Group, Inc. and its affiliates from certain claims.  The enhanced benefit is expressed as a lump sum amount equal to three weeks of pay (using Average Annual Base Salary and Average Incentive Award) per year of Credited Service (as defined under the Pension Plan).  Participants who receive such enhanced benefits are not eligible for benefits under any severance plan or arrangement.

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EX-10.(O)

Exhibit 10(o)

CONSTELLATION ENERGY GROUP, INC.

SENIOR EXECUTIVE SUPPLEMENTAL PLAN

1.Objective.  The objective of this Plan is to enhance the benefits provided to certain senior executives of Constellation Energy Group and its subsidiaries in order to attract and retain talented executive personnel.

2.Definitions.  All words beginning with an initial capital letter and not otherwise defined herein shall have the meaning set forth in the Pension Plan.   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:

“Average Annual Base Salary” means an amount determined by (a) computing the monthly base rate of pay amounts (i.e., the types of such pay that are includable in the computation of Pension Plan benefits) paid during the prior five consecutive twelve month periods immediately preceding the month that includes the date of the computation, and (b) averaging the two twelve month periods during which the highest amounts were paid.

“Average Incentive Award” (or “Average Award”) means the average of the two highest of the participant’s five immediately prior year awards earned under Constellation Energy Group’s Executive Annual Incentive Plan, Constellation Energy Group’s Senior Management Annual Incentive Plan and/or Other Incentive Awards Programs.

“Benefit Start Date” means the date as of which the participant’s benefits, if any, under this Plan commence.

“Cause” means the participant’s (a) failure to comply with Constellation Energy Group policy, (b) deliberate and continual refusal to satisfactorily perform employment duties on substantially a full-time basis, (c) deliberate and continual refusal to act in accordance with any specific instructions of a majority of Constellation Energy Group’s Board of Directors, (d) disclosure, without the consent of a majority of Constellation Energy Group’s Board of Directors, of confidential information or trade secrets concerning Constellation Energy Group which could be materially damaging to Constellation Energy Group, or (e) deliberate

misconduct which could be materially damaging to Constellation Energy Group without reasonable good faith belief by the participant that such conduct was in the best interest of Constellation Energy Group.

“Change in Control” means (a) the purchase or acquisition by any person, entity or group of persons, (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), or any comparable successor provisions), of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20 percent or more of either the outstanding shares of common stock of Constellation Energy Group or the combined voting power of Constellation Energy Group’s then outstanding shares of voting securities entitled to a vote generally, or (b) the consummation of, following the approval by the stockholders of Constellation Energy Group of a reorganization, merger, or consolidation of Constellation Energy Group, in each case, with respect to which persons who were stockholders of Constellation Energy Group immediately prior to such reorganization, merger or consolidation do not, immediately thereafter, own more than 50 percent of the combined voting power entitled to vote generally in the election of directors of the reorganized, merged or consolidated entity’s then outstanding securities, or (c) a liquidation or dissolution of Constellation Energy Group or the sale of substantially all of its assets, or (d) a change of more than one-half of the members of the Board of Directors of Constellation Energy Group within a 90-day period for reasons other than the death, disability, or retirement of such members.

“Committee” means the Committee on Management of the Board of Directors of Constellation Energy Group.

“Constellation Energy Group” means Constellation Energy Group, Inc., a Maryland corporation, or its successor.

“Constellation Energy Group’s Executive Annual Incentive Plan” means such plan or other incentive plan or arrangement designated in writing by the Plan Administrator.

“Constellation Energy Group’s Senior Management Annual Incentive Plan” means such plan or other incentive plan or arrangement designated in writing by the Plan Administrator.

“Demotion” means a transfer to a position with Constellation Energy Group or a subsidiary of Constellation Energy Group

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that either (a) is substantially below the position in which the participant was employed on the date of transfer, or (b) results in a substantial reduction in pay when compared to the participant’s pay on the date of the transfer.  Whether a position is substantially below another position shall be determined in the reasonable discretion of the Committee, with reference to factors including whether the participant retains principal responsibility for a department or division, and whether the participant remains eligible for the perquisites enjoyed by the participant before the position change.

“Early Receipt Reduction Factor” means 100% less 1/3 of 1% for each month that the participant is less than age 62 on the participant’s Benefit Start Date.

“Interest Rate” means the rate equal to the average monthly 30-year Treasury bond rate for the second calendar quarter preceding the computation date, less 50 basis points.

“Internal Revenue Code Limitations” means the limitations under Section 415 and/or 401(a)(17) of the Internal Revenue Code.

“LTD Plan” means the Constellation Energy Group, Inc. Disability Insurance Plan as may be amended from time to time, or any successor plan.

“Mortality Table” means the mortality table used to convert annuities to lump sums in the Pension Plan.

“Nonqualified Deferred Compensation Plan” means the Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan.

“Other Incentive Awards Program” means the program(s) designated in writing by the Plan Administrator applicable to certain employees that provides awards; but includes only the types of awards that are includable in the computation of Pension Plan benefits.

“Pension Plan” means the Pension Plan of Constellation Energy Group, Inc. as may be amended from time to time, or any successor plan.

“Plan” means this Constellation Energy Group, Inc. Senior Executive Supplemental Plan.

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“Plan Administrator” means, as set forth in Section 3, the Committee.

“Rabbi Trust” means the trust adopted by Constellation Energy Group pursuant to the Grantor Trust Agreement Dated as of January 1, 2001, between Constellation Energy Group and Citibank, N.A.

“Survivor Annuity Percentage” means 50%, unless the participant elects, in the timing and manner established by the Plan Administrator, a higher percentage (in multiples of 5% to a total percentage not to exceed 100%).

“Termination From Employment With Constellation Energy Group” means a participant’s separation from service with Constellation Energy Group or a subsidiary of Constellation Energy Group; however, a participant’s retirement, disability, or transfer of employment to or from a subsidiary of Constellation Energy Group shall not constitute a Termination From Employment With Constellation Energy Group.

“Total SERP Service” means (a) Credited Service accumulated while designated as a participant with respect to supplemental pension benefits under this Plan or while a participant under the Constellation Energy Group Supplemental Pension Plan, or while a participant under any predecessor executive supplemental pension benefit plan, plus (b) one fourth of Credited Service accumulated while not such a participant.

3.Plan Administration.  The Committee is the Plan Administrator and has sole authority (except as specified otherwise herein) to interpret the Plan and, in general, to make all other determinations advisable for the administration of the Plan to achieve its stated objective.  Appeals of written decisions by the Plan Administrator may be made to the Board of Directors of Constellation Energy Group.  Decisions by the Board shall be final and not subject to further appeal.  The Plan Administrator shall have the power to delegate all or any part of its duties to one or more designees, and to withdraw such authority, by written designation.

4.Eligibility.  Each senior executive of Constellation Energy Group or its subsidiaries may be designated in writing by the Plan Administrator as a participant with respect to one or more benefits under the Plan. Once designated,

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participation shall continue until such designation is withdrawn at the discretion and by written order of the Plan Administrator, provided, however, that such withdrawal may not be made with respect to a participant who has satisfied the eligibility requirements to retire (as set forth in Section 5(b)(i)).  Notwithstanding the foregoing, any participant while classified as disabled under the LTD Plan shall continue to participate in this Plan while classified as disabled and, for purposes of the supplemental pension benefit provided by this Plan, while classified as disabled, shall be deemed to continue to accrue Credited Service until no later than his/her Normal Retirement Date.

5.Supplemental Pension Benefit.

(a)Generally.

(i)A Plan participant who was a participant in the Constellation Energy Group Supplemental Pension Plan on January 1, 2000, shall be eligible for supplemental pension benefits under this Plan only if the participant’s supplemental pension benefits under this Plan are greater than the supplemental pension benefits computed under the Constellation Energy Group Supplemental Pension Plan based on the participant’s age, service, and eligible compensation on the date as of which benefits become payable. If a participant or a participant’s surviving spouse receives benefits from this Plan, he/she cannot also receive benefits from the Constellation Energy Group Supplemental Pension Plan.

(ii)Any other participant in the Plan shall be eligible for benefits under this Plan without regard to any computation under the Constellation Energy Group Supplemental Pension Plan.

(b)           Retirement benefits.

(i)Eligibility for retirement benefits. A participant shall be eligible to retire under this Plan on or after the participant’s Normal Retirement Date, or on the first day of any month preceding his/her Normal Retirement Date, if on his/her Severance From Service Date and while a participant he/she has attained (1) age 55 and has accumulated at least 10 years of Credited Service; or (2) age 62 and has accumulated at least five years of Credited Service.

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(ii)Computation of retirement benefits. A participant who is eligible to retire under this Plan will be entitled to supplemental pension retirement benefits under this Plan, which will be calculated as set forth below on the participant’s Benefit Start Date:

(1)add the Average Annual Base Salary and the Average Incentive Award,

(2)divide the sum by 12,

(3)multiply this dollar amount by the appropriate percentage, determined as follows: Chairman of the Board and President of Constellation Energy Group - 60%; all other participants (the product of 5.5% multiplied by the number of full and fractional years of Total SERP Service), (maximum is 55%).

(4)multiply this dollar amount by the Early Receipt Reduction Factor; provided, however, if the participant is age 62 or older on his/her Benefit Start Date, such factor shall be one (1),

(5)subtract from this dollar amount the charges relating to coverage for a pre-retirement survivor annuity in excess of 50%, and for a post-retirement survivor annuity in excess of 50%, and

(6)subtract from the remainder the net monthly amount payable to the participant under the Pension Plan on the participant’s Benefit Start Date (assuming a 50% spousal joint and survivor annuity for a married participant), (if the participant is not eligible to commence monthly Pension Plan payments on the participant’s Benefit Start Date, the participant’s benefit will be unreduced for Pension Plan payments until the date the participant is first eligible to commence monthly Pension Plan payments),or, if the participant elects a lump sum under the PEP provisions of the Pension Plan, the monthly

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amount that would have been payable under the Pension Plan as a life annuity for a single participant or as a 50% spousal joint and survivor annuity for a married participant, as of the Benefit Start Date under this Plan.

(iii)Form of payout of retirement benefits.  Each participant entitled to supplemental pension retirement benefits will receive his/her supplemental pension retirement benefits payout in the form of a monthly payment, unless the participant makes a valid election to receive his/her supplemental pension retirement benefits payout in the form of a lump sum.

A participant may elect to receive his/her supplemental pension retirement benefits payout in the form of a lump sum by submitting to the Plan Administrator a signed Lump Sum Election Form.  On such Form, the participant may elect to rollover such payout directly to the Nonqualified Deferred Compensation Plan.  The Form must be received by the Plan Administrator before the beginning of the calendar year during which the participant’s Severance From Service Date occurs.  The election to receive a payout in the form of a lump sum, or to rollover such payment to the Nonqualified Deferred Compensation Plan, may be revoked at any time before the beginning of the calendar year during which the participant’s Severance From Service Date occurs, by submitting to the Plan Administrator a signed Lump Sum Revocation Form.

(iv)Amount, timing, and source of monthly retirement benefit payout.  A participant entitled to monthly supplemental pension retirement benefits will receive monthly payments equal to the amount determined under paragraph (b)(ii).  Such payments shall commence effective with the first of the month following the Participant’s Severance From Service Date.  If such participant receives (or would have received but for the Internal Revenue Code Limitations) cost of living adjustment(s) under the Pension Plan, the monthly payments hereunder will be automatically increased based on the percentage of, and at the same time as, such adjustment(s).  Monthly payments hereunder shall permanently cease upon the death of the

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participant, effective with the monthly payment for the month following the month of the participant’s death.  Monthly payments hereunder shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets.

(v)Amount, timing, and source of lump sum retirement benefit payout.  A participant entitled to a lump sum supplemental pension retirement benefit will receive a lump sum payment.  This lump sum payment will be calculated by a certified actuary and will be equal to the present value of an immediate annuity including the estimated present value of post-retirement supplemental survivor annuity benefits described in Section 6, and reflecting the present value of any deferred Pension Plan payments using (1) the supplemental pension retirement benefit amount calculated under paragraph (b)(ii), which is expressed as a monthly amount, (2) the Interest Rate computed on the participant’s Benefit Start Date, and (3) the Mortality Table.  Such lump sum payment shall be made within 60 days after the participant’s Severance From Service Date, and shall either be paid to the participant, or rolled over to the Nonqualified Deferred Compensation Plan pursuant to the participant’s election under (b)(iii).  The lump sum payment shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets.  A participant who receives or rolls over a lump sum payment shall not be entitled to any cost of living or other pension payment adjustments or to post-retirement survivor annuity coverage under the Plan.

(vi)Death of participant entitled to lump sum payout.  In the event of the death of a participant after his/her Severance From Service Date and before the participant receives or rolls over the lump sum payment under paragraph (b)(v), such lump sum payment shall be made to the participant’s surviving spouse (as defined in Section 6(i)).  The lump sum payment shall be the same amount and made at the same time and from the same sources as

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set forth in paragraph (b)(v).  If there is no surviving spouse at the date of the participant’s death, no payments shall be made pursuant to Sections 5 or 6.  A surviving spouse who receives a lump sum benefit under this paragraph (b)(vi) shall not be entitled to any cost of living or other pension payment adjustments or to post-retirement survivor annuity coverage under the Plan.

(c)Entitlement to benefit upon happening of certain events.

(i)Computation of gross accrued benefit.  The computation of the gross accrued supplemental pension benefit for a participant as of the date of the computation will be made as follows:

(1)add the Average Annual Base Salary and the Average Incentive Award,

(2)divide the sum by 12, and

(3)multiply this dollar amount by the appropriate percentage, determined as follows: Chairman of the Board and President of Constellation Energy Group — 60%; all other participants (by the product of 5.5% multiplied by the number of full and fractional years of Total SERP Service as of the date of the computation) (maximum is 55%).

(ii)Computation of net accrued benefit.  The computation of the net accrued supplemental pension benefit for a participant as of the date of the computation will be made by subtracting from the gross accrued benefit determined under paragraph (c)(i) the amount of the participant’s Gross Pension under the Pension Plan determined as of the date of the computation and assuming that monthly payments of such Gross Pension begin on the first of the month after the later of reaching age 62 or the date of the computation.  If the participant is not eligible for payment of a Gross Pension under the Pension Plan, the participant’s Accrued Gross Pension determined as of the date of

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the computation shall be substituted for the Gross Pension described above, with the appropriate reduction for early receipt applied as if the participant were eligible to begin payment of his Accrued Gross Pension on the first of the month after the later of reaching age 62 or the date of the computation.

(iii)Satisfaction of requirements.  A participant who has satisfied the age and Credited Service requirements set forth in Section 5(b)(i) while eligible as set forth in Section 4, but who does not retire under the Plan due to Demotion, Termination From Employment With Constellation Energy Group, or the withdrawal of a participant’s eligibility to participate under Section 5, shall be entitled to his/her net accrued supplemental pension benefit.  The effective date of the Demotion, Termination From Employment With Constellation Energy Group, or eligibility withdrawal event shall be the date of such Demotion, Termination From Employment With Constellation Energy Group, or eligibility withdrawal.

(iv)Other events.  A participant, regardless of his/her age and years of Credited Service, shall be entitled to his/her net accrued supplemental pension benefit upon the happening of any of the following entitlement events, but only if such entitlement event occurs while a participant and before a participant retires under this Plan:

(1)Change in Control.  A Change in Control, followed within two years by the participant’s Demotion, a participant’s Termination From Employment With Constellation Energy Group, or the withdrawal of the participant’s eligibility to participate under the Plan, is an entitlement event.  The effective date of the entitlement event shall be the date of the Demotion, Termination From Employment With Constellation Energy Group, or eligibility withdrawal.

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(2)Plan amendment.  A Plan amendment that has the effect of reducing a participant’s gross accrued supplemental pension benefit is an entitlement event.  In determining whether such a reduction has occurred, the participant’s gross accrued supplemental pension benefit calculated on the day immediately preceding the effective date of the amendment shall be compared to the participant’s gross accrued supplemental pension benefit calculated on the effective date of the amendment.  An amendment that has the effect of reducing future benefit accruals is not an entitlement event.  It is intended that an entitlement event under this paragraph (c)(iii)(2) will occur only with respect to those amendments that are substantially similar to amendments that are prohibited by Internal Revenue Code section 411(d)(6) with respect to qualified pension plans.  The effective date of the entitlement event shall be the effective date of the Plan amendment.

(3)Involuntary Demotion, Termination From Employment With Constellation Energy Group, or eligibility withdrawal without Cause.  A participant’s involuntary Demotion or involuntary Termination From Employment With Constellation Energy Group without Cause, or the withdrawal of a participant’s eligibility to participate under Sections 5 or 6 of the Plan without Cause, is an entitlement event.  The effective date of the entitlement event shall be the effective date of the participant’s involuntary Demotion or involuntary Termination From Employment With Constellation Energy Group without Cause, or the eligibility withdrawal without Cause.

(v)Form of benefit payout. Each participant entitled to a payout under this paragraph (c) will receive such payout in the form of a lump sum payment.

(vi)Amount, timing, and source of benefit payout.  A participant entitled to a payout of his/her net accrued benefit, as a result of the occurrence of

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an event described in paragraphs (c)(iii), (c)(iv)(1), (2), or (3) will be entitled to a lump sum benefit.  This lump sum benefit will be calculated by a certified actuary  as the present value, determined as of the date of payment, of an annuity beginning at age 62 (or the participant’s actual age, if the participant is older than age 62 on the date the lump sum benefit is payable), including the estimated present value of post-retirement survivor annuity benefits described in Section 6, using (1) the net accrued benefit amount calculated under paragraph (d)(iv) on the effective date of the entitlement event, which is expressed as a monthly amount, (2) the Interest Rate computed on the date the lump sum benefit is payable, and (3) the Mortality Table.  The lump sum benefit shall be payable as of the participant’s Severance From Service Date, and shall be made within 60 days after such date in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets.  A participant who receives a lump sum benefit under this paragraph (c)(vi) shall not be entitled to any cost of living or other pension payment adjustments or to pre-retirement or post-retirement survivor annuity coverage.

(vii)Death of participant entitled to lump sum payout.  In the event of the death of a participant after the occurrence of an event described in paragraphs (c)(iii), (c)(iv)(1), (2), or (3) and before the participant receives the lump sum payment under paragraph (c)(vi), a lump sum payment shall be made to the participant’s surviving spouse (as defined in Section 6(i)).  The lump sum payment will be calculated by a certified actuary and will be equal to 100% of the lump sum that would have been paid to the participant under paragraph (vi), as of the date on which the lump sum is payable under this paragraph (vii), provided that the participant’s date of death is on or after his/her Severance From Service Date.  If the participant’s date of death is before his/her Severance From Service Date, 50% shall be substituted for 100% in the preceding sentence.  The lump sum benefit shall be payable as of the earlier of the participant’s Severance From Service Date or date

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of death, and shall be made within 60 days after such date in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets.  If there is no surviving spouse at the date of the participant’s death, no payments shall be made pursuant to Sections 5 or 6.  A surviving spouse who receives a lump sum benefit under this paragraph (c) (vii) shall not be entitled to any cost of living or other pension payment adjustments or to pre-retirement or post-retirement survivor annuity coverage under the Plan.

6.Supplemental Survivor Annuity Benefit.

(a)Survivor annuity benefit.

(i)Eligibility for survivor annuity benefit.  Following the death of a participant who is fully vested under the Pension Plan, a supplemental survivor annuity may be paid to the participant’s surviving spouse until the death of that spouse, using the Survivor Annuity Percentage. The participant will not bear the cost of up to a 50% survivor annuity benefit, but will bear the cost of a survivor annuity benefit in excess of 50%.  For purposes of this Section 6(a), a participant’s surviving spouse is the individual married to the participant on the date of the participant’s death.  If there is no surviving spouse, or if the participant or the participant’s spouse previously received or is entitled to receive a lump sum payment under Section 5, no supplemental survivor annuity will be payable.

(ii)Computation of survivor annuity benefit.  The amount of the supplemental survivor annuity will be determined as follows:

(1)if the participant’s Benefit Start Date occurred prior to the date of death:

(a)begin with the monthly pension benefit (under Section 5(b) of this Plan) that

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the participant was receiving prior to the date of death, and

(b)multiply this dollar amount by the Survivor Annuity Percentage.

(2)otherwise:

(a)Unless the participant elected the alternative in-service death benefit in section (b) below:

(1)begin with the  monthly Early Retirement pension benefit (under both the Pension Plan and Section 5(b) of this Plan) to which the participant would have been entitled if the participant had been retired at the later of age 60 or his/her actual age on the date of death for purposes of computing the Early Receipt Reduction Factor,

(2)multiply this dollar amount by the Survivor Annuity Percentage,

(3)subtract from the product the net amount, if any, of the survivor annuity provided on behalf of the participant under the Pension Plan if the participant is participating in the Traditional Pension Plan, or the monthly annuity that would have been provided to the participant’s spouse assuming that he or she had been designated as the participant’s beneficiary and had chosen to receive a survivor benefit in the form of a monthly annuity, if the participant is participating in the PEP, and

(4)subtract from this dollar amount the charges relating to coverage (under both the Pension Plan and this Plan) for a pre-retirement survivor annuity in excess of 50%.

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(b)If the participant was a participant in the Pension Equity Plan option of the Pension Plan and elected this alternative in-service death benefit by December 31 of the year prior to his/her death or during the 2001 initial election period established by the Plan Administrator

(1)calculate the benefit under the Constellation Energy Group Benefits Restoration Plan that would have been payable to the surviving spouse if the participant were a participant in that plan and

(2)that dollar amount will be paid to the surviving spouse only in the form of a lump sum from this Plan.

(iii)Form of payout of survivor annuity benefits. Unless the participant made a valid election by December 31 of the year prior to his/her death or during the 2001 initial election period established by the Plan Administrator, to have the survivor benefits paid in a lump sum, each surviving spouse entitled to a supplemental survivor annuity benefit will receive his/her survivor annuity benefit payout in the form of a monthly payment.

(iv)Amount, timing, and source of monthly survivor annuity benefit payout.  A surviving spouse entitled to monthly supplemental survivor annuity benefits will receive a monthly payment equal to the amount determined under (ii) above.  Such payments shall commence effective with the first day of the month following the month of the participant’s death.  If such surviving spouse receives (or would have received but for the Internal Revenue Code Limitations) cost of living adjustment(s) under the Pension Plan, the monthly payments hereunder will be automatically increased based on the percentage of, and at the same time as, such adjustment(s).  Monthly payments hereunder shall permanently cease upon the death of the surviving spouse, effective with the monthly payment for the month following the month

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of the surviving spouse’s death.  Monthly payments hereunder shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets.

(v)Amount, timing, and source of lump sum survivor benefit payout. A surviving spouse entitled to lump sum supplemental survivor benefit will receive a lump sum payment.  This lump sum payment will be calculated by a certified actuary and will be equal to the present value of an immediate annuity. Such lump sum payment shall be made within 60 days after the participant’s death.  The lump sum payment shall be made in accordance with the provisions of the Rabbi Trust and, to the extent not paid under the terms of the Rabbi Trust, from general corporate assets.  A surviving spouse who receives a lump sum payment shall not be entitled to any cost of living or other pension payment adjustments.

(vi)Death of surviving spouse entitled to lump sum payout.  In the event of the death of a surviving spouse before the spouse receives the lump sum payment under section 6(a)(v) no payment shall be made.

7.Death Benefit.  Constellation Energy Group shall make arrangements, through its split-dollar life insurance program or otherwise, for life insurance coverage for each designated participant providing that the participant’s beneficiary shall receive, as a pre-retirement (or pre-rollout benefit for participants as of April 1, 2000 death benefit, an amount which is approximately equal to three times the participant’s base salary control point plus target annual incentive (as determined in the sole discretion of the Plan Administrator), and as a post-retirement death benefit(or post-rollout benefit for participants as of April 1, 2000, an amount which is approximately equal to two times the participant’s base salary control point plus target annual incentive (as determined in the sole discretion of the Plan Administrator), as set forth in a separate agreement between the participant and his/her employer.

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As determined in the sole discretion of the Plan Administrator, in the event that either (i) a participant is ineligible to receive the type of life insurance coverage provided to other participants under this Plan, or (ii) such coverage is not available on reasonably cost-effective terms as a result of any penalty for smoking or other factors that are reflected in the insurance carrier’s rates, then Constellation Energy Group shall provide a benefit that, in the discretion of the Plan Administrator, is substantially equivalent to the cost of the benefit provided to other participants under this Plan.

8.Dependent Death Benefit.  For a participant with a split-dollar policy under Section 7, in the event of the death of a participant’s qualified dependent while the participant is an active employee of Constellation Energy Group or a subsidiary of Constellation Energy Group, Constellation Energy Group shall make a death benefit payment to the participant, from general corporate assets.  For purposes of this Section 8, qualified dependent shall have the same meaning as set forth in Constellation Energy Group’s Family Life Insurance Plan.  For purposes of this Section 8, the amount of death benefit payment shall be the highest amount of insurance that would have been payable with respect to such qualified dependent if coverage had been provided under Constellation Energy Group’s Family Life Insurance Plan.  The dependent death benefit payment under this Plan shall be grossed-up for income tax withholding.

9.Miscellaneous.  None of the benefits provided under this Plan shall be subject to alienation or assignment by any participant or beneficiary nor shall any of them be subject to attachment or garnishment or other legal process except (i) to the extent specially mandated and directed by applicable State or Federal statute; (ii) as requested by the participant or beneficiary to satisfy income tax withholding or liability; and (iii) any policy of insurance written by a commercial carrier on a split-dollar basis shall be assignable.

This Plan may be amended from time to time, or suspended or terminated at any time, provided, however, that no amendment or termination shall reduce any previously accrued supplemental pension benefit under this Plan or impair the rights of any participant or beneficiary entitled to receive current or future payment hereunder at the time of such action.  All amendments to this Plan may be made at the written direction of the Committee. Notwithstanding anything

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else in this Plan to the contrary, the Constellation Energy Group Board of Directors may authorize a Participant to be eligible for benefits or may increase benefit payments.

Participation in this Plan shall not constitute a contract of employment between Constellation Energy Group or any of its subsidiaries and any person and shall not be deemed to be consideration for, or a condition of, continued employment of any person.

The Plan, notwithstanding the creation of the Rabbi Trust, is intended to be unfunded for purposes of Title I of the Employee Retirement Income Security Act of 1974.  Constellation Energy Group shall make contributions to the Rabbi Trust in accordance with the terms of the Rabbi Trust.  Any funds which may be invested and any assets which may be held to provide benefits under this Plan shall continue for all purposes to be a part of the general funds and assets of Constellation Energy Group and no person other than Constellation Energy Group shall by virtue of the provisions of this Plan have any interest in such funds and assets.  To the extent that any person acquires a right to receive payments from Constellation Energy Group under this Plan, such rights shall be no greater than the right of any unsecured general creditor of Constellation Energy Group.

In the event Constellation Energy Group becomes a party to a merger, consolidation, sale of substantially all of its assets or any other corporate reorganization in which Constellation Energy Group will not be the surviving corporation or in which the holders of the common stock of Constellation Energy Group will receive securities of another corporation (in any such case, the “New Company”), then the New Company shall assume the rights and obligations of Constellation Energy Group under this Plan.

This Plan shall be governed in all respects by Maryland law.

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Amendments to the Constellation Energy Group, Inc.

Senior Executive Supplemental Plan (Plan)

1.             Notwithstanding anything in Section 5(b)(iii) of the Plan to the contrary, any participant who terminates employment in connection with the management restructuring announced late in 2001, and who wants to receive a lump sum payout of his/her Plan benefit in 2002, must irrevocably elect by December 31, 2001 to rollover the present value of his/her accrued benefit under the Plan to the Nonqualified Deferred Compensation Plan effective December 31, 2001.  Any additional benefit accruals under the Plan during 2002 and prior to employment termination will automatically be paid in a lump sum from the Plan within 60 days after employment termination.

2.             Notwithstanding anything in Section 5(b)(ii) to the contrary, participants designated by the Plan Administrator who are at least age 55 with 10 or more years of service as of January 31, 2002 and who make an irrevocable election in the time and manner established by the Plan Administrator to voluntarily retire on February 1, 2002 (or such later date on or before July 1, 2002 as required in the sole discretion of management), is entitled to an enhanced early retirement benefit conditioned on such participants’ execution of a waiver releasing Constellation Energy Group, Inc. and its affiliates from certain claims.  The enhanced benefit is expressed as a lump sum amount equal to three weeks of pay (using Average Annual Base Salary and Average Incentive Award) per year of Credited Service (as defined under the Pension Plan).  Participants who receive such enhanced benefits are not eligible for benefits under any severance plan or arrangement.

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EX-10.(P)

Exhibit 10(p)

CONSTELLATION ENERGY GROUP, INC.

SUPPLEMENTAL BENEFITS PLAN

1.Objective.  The objective of this Plan is to enhance the benefits provided to certain officers and key employees of Constellation Energy Group and its subsidiaries in order to attract and retain talented executive personnel.

2.Definitions.  All words beginning with an initial capital letter and not otherwise defined herein shall have the meaning set forth in the Pension Plan.   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:

“Average Incentive Award” (or “Average Award”) means the average of the two highest of the participant’s five immediately prior year awards earned under Constellation Energy Group’s Executive Annual Incentive Plan, Constellation Energy Group’s Senior Management Annual Incentive Plan and/or the Other Incentive Awards Program.

“Committee” means the Committee on Management of the Board of Directors of Constellation Energy Group.

“Constellation Energy Group” means Constellation Energy Group, Inc., a Maryland corporation, or its successor.

“Constellation Energy Group’s Executive Annual Incentive Plan” means such plan or other incentive plan or arrangement designated in writing by the Plan Administrator.

“Constellation Energy Group’s Senior Management Annual Incentive Plan” means such plan or other incentive plan or arrangement designated in writing by the Plan Administrator.

“Income Replacement Percentage” means the percentage under the LTD Plan that is used to calculate the participant’s actual LTD Plan benefit.

“LTD Plan” means the Constellation Energy Group, Inc. Disability Insurance Plan as may be amended from time to time, or any successor plan.

“Other Incentive Awards Program” means the program(s) designated in writing by the Plan Administrator applicable to certain employees that provides awards; but includes only the types of awards that are includable in the computation of Pension Plan benefits.

“Pension Plan” means the Pension Plan of Constellation Energy Group, Inc. as may be amended from time to time, or any successor plan.

“Plan Administrator” means, as set forth in Section 3, the Committee.

3.Plan Administration.  The Committee is the Plan Administrator and has sole authority (except as specified otherwise herein) to interpret the Plan and, in general, to make all other determinations advisable for the administration of the Plan to achieve its stated objective.  Appeals of written decisions by the Plan Administrator may be made to the Board of Directors of Constellation Energy Group.  Decisions by the Board shall be final and not subject to further appeal.  The Plan Administrator shall have the power to delegate all or any part of its duties to one or more designees, and to withdraw such authority, by written designation.

4.Eligibility.  Each officer or key employee of Constellation Energy Group or its subsidiaries may be designated in writing by the Plan Administrator as a participant with respect to one or more benefits under the Plan. Once designated, participation shall continue until such designation is withdrawn at the discretion and by written order of the Plan Administrator.  Notwithstanding the foregoing, any participant while classified as disabled under the LTD Plan shall continue to participate in this Plan (except under Sections 6 and 7) while classified as disabled.

5.Supplemental Long-Term Disability Benefit.

(i)Eligibility for disability benefits.  Any participant who has completed at least one full calendar month of service with Constellation Energy Group or its subsidiaries, who has elected coverage under the LTD Plan, and who is disabled (as determined under the LTD Plan) will be entitled to supplemental disability benefits under this Plan.

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(ii)Computation of disability benefits.  The amount of such supplemental disability benefits shall be determined as follows:

(1)multiply the monthly base rate of pay amount in effect immediately prior to becoming entitled to benefits under the LTD Plan by twelve,

(2)add the Average Incentive Award to the product,

(3)add certain bonuses and incentives that are included in the computation of Average Pay under the Pension Plan (except that awards included in the computation of Average Incentive Award shall be excluded), earned over the last 12 months to the product,

(4)divide the sum by 12,

(5)multiply this monthly dollar amount by the Income Replacement Percentage, and

(6)subtract from the product the gross monthly amount provided for the participant under the LTD Plan before such amount is reduced for other benefits as set forth under the LTD Plan.

(iii)Form of payment of disability benefits.  Each participant entitled to supplemental disability benefits will receive his/her supplemental disability benefit payout in the form of a monthly payment.

(iv)Amount, timing, and source of monthly disability benefit payout.  A participant entitled to supplemental disability benefits will receive a monthly payment equal to the amount determined under (ii) above.  Such payments shall commence effective with the commencement of the participant’s LTD Plan benefit payments.  Monthly payments shall permanently cease when benefit payments under the LTD Plan cease.  Monthly payments shall be made from Constellation Energy Group’s general corporate assets.

If a participant receiving payments pursuant to this Section 5 receives cost of living or other inflation/indexing adjustment(s) under the LTD Plan,

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the payments hereunder will be automatically increased based on the same percentage of, and at the same time as, such adjustment(s).

(v)Bonus.  Any participant who has less than ten years of Credited Service shall be entitled to a monthly taxable cash bonus, equal to an amount based on the cost of LTD Plan coverage, using the formula for computing Constellation Energy Group-provided Flexible Benefits Plan credits for LTD Plan coverage and taking into account the Participant’s Credited Service and covered compensation.  Such cash bonus shall be made from  general corporate assets.

6.Sickness Benefit.  Each participant, without regard to length of service, shall be entitled to the greater of the benefits stipulated under his/her employer’s sick benefit policy for employees or twenty-six (26) weeks of paid sick benefits within a rolling 52-week period.

7.Vacation Benefit.  Each participant, without regard to length of service, shall be entitled to the greater of the benefits stipulated under his/her employer’s vacation benefit policy for employees or five weeks of paid vacation during a calendar year.

8.Planning Benefit.  Each participant shall be entitled to certain personal financial, tax, and estate planning services paid for by Constellation Energy Group but provided through designated professional firms.  This entitlement shall be subject to any dollar limitation established by the Plan Administrator with respect to all such fees.  The services shall be provided to each participant by the chosen firm(s) on a personalized and confidential basis; and each firm shall have sole responsibility for quality of the services which it may render.

The services to be provided shall be on an on-going and continuous basis, but shall be limited to (i) the development and legal documentation of both career-oriented financial plans and personal estate plans, and (ii) tax counseling regarding personal tax return preparation and the most advantageous structuring, tax-wise, of proposed personal transactions.

Such planning benefit shall continue during the year of retirement plus the next two calendar years (the year of

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retirement plus the next calendar year for January 1 retirements) and include the completion of the federal and state personal tax returns for the second calendar year following retirement (the calendar year following retirement for January 1 retirements).  However, if a retired member of senior management continues to serve as a member of the Board of Directors of Constellation Energy Group, his/her planning benefit period shall be extended until he/she no longer serves as a member of the Board of Directors.

Upon the death of a participant entitled to the planning benefit provided hereunder, his/her surviving spouse shall be entitled to receive the following planning benefit: (i) if the deceased was not retired at the time of death, the surviving spouse shall be entitled to the planning benefit for the year in which the death occurred plus the next two calendar years, including completion of the federal and state personal tax returns for the second calendar year after the year in which the death occurred; or (ii) if the deceased was retired at the time of death, then the surviving spouse shall receive a planning benefit equal to that the deceased would have received if he/she had not died prior to expiration of the planning benefit.  The surviving spouse of a retired member of senior management whose death occurs while serving as a member of the Board of Directors of Constellation Energy Group, shall be entitled to a planning benefit as set forth in (i) above.

The planning benefit provided under this Plan shall be grossed-up for income tax withholding.

9.Miscellaneous.  None of the benefits provided under this Plan shall be subject to alienation or assignment by any participant or beneficiary nor shall any of them be subject to attachment or garnishment or other legal process except (i) to the extent specially mandated and directed by applicable State or Federal statute and (ii) as requested by the participant or beneficiary to satisfy income tax withholding or liability.

This Plan may be amended from time to time, or suspended or terminated at any time, provided, however, that no amendment or termination shall impair the rights of any participant or beneficiary entitled to receive current or future payment hereunder at the time of such action.  All amendments to this Plan may be made at the written direction of the Committee.

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Participation in this Plan shall not constitute a contract of employment between Constellation Energy Group or a subsidiary of Constellation Energy Group and any person and shall not be deemed to be consideration for, or a condition of, continued employment of any person.

All payments made under the Plan shall be made from general corporate assets.  The Plan, is intended to be unfunded for purposes of Title I of the Employee Retirement Income Security Act of 1974.  To the extent that any person acquires a right to receive payments from Constellation Energy Group under this Plan, such rights shall be no greater than the right of any unsecured general creditor of Constellation Energy Group.

In the event Constellation Energy Group becomes a party to a merger, consolidation, sale of substantially all of its assets or any other corporate reorganization in which Constellation Energy Group will not be the surviving corporation or in which the holders of the common stock of Constellation Energy Group will receive securities of another corporation (in any such case, the “New Company”), then the New Company shall assume the rights and obligations of Constellation Energy Group under this Plan.

This Plan shall be governed in all respects by Maryland law.

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EX-10.(Q)

Exhibit 10(q)
Attachment 1

EMPLOYMENT AGREEMENT

This Employment Agreement (the “Agreement”) is made as of the 20^th day of December, 2001 by and between  Constellation Energy Group, Inc. (“Company”) and Michael J. Wallace (“Executive”).

WITNESSETH:

WHEREAS, Company desires to employ Executive and Executive is willing to accept such employment, all upon the terms and conditions hereinafter set forth.

NOW, THEREFORE, in consideration of the mutual covenants and obligations hereinafter set forth, the parties hereto agree as follows:

1.             Employment Term.  Company hereby employs Executive and Executive accepts employment with Company as President of the Company’s Generation Group on the terms and conditions herein set forth, for a period commencing on January 2, 2002 and expiring on December 31, 2004 (the “Term”).   Executive’s duties and responsibilities shall be determined by Company’s Chief Executive Officer (“CEO”) consistent with Executive’s qualifications and the best interests of Company.  Executive also shall perform such other or additional duties as may be assigned to him by the CEO from time to time as are reasonably consistent with the position of President or such other position as may be mutually agreed upon by the parties.

2.             Duties.  During the term hereof, Executive shall devote his entire attention and energy to the business and affairs of Company on a full-time basis during normal business hours, and as reasonably required, outside normal business hours, and shall not be engaged in any other business activity, regardless of whether such business activity is pursued for gain, profit or other

pecuniary advantage, unless the CEO otherwise consents in writing; but this shall not be construed as preventing Executive from investing his assets in such form or manner as will not require any services on the part of the Executive in the operation of the affairs of the companies in which such investments are made and will not otherwise conflict with the provisions of this Agreement.

3.             Compensation.

(a)           Base Salary.  During the first year of this Agreement, Company shall pay Executive an annual base salary of Five Hundred Thousand Dollars ($500,000) (the “Base Salary”, subject to adjustment as provided in the next sentence), payable in accordance with Company’s regular payroll procedures.  Company will review Executive’s Base Salary for possible increases at least annually.

(b)           Incentive Plan.  During the term of this Agreement, Executive shall be eligible to participate in Company’s annual incentive plan for executives, which shall have a target performance bonus totaling up to an additional one hundred percent (100%) of Base Salary for the first year of this Agreement based on achieving reasonably attainable individual and overall Company performance goals.  For the first year of this Agreement, the maximum performance bonus of Five Hundred Thousand Dollars ($500,000) will be guaranteed, and it will be paid in accordance with the terms of the current Executive Annual Incentive Plan.  Following the first year of this Agreement and during the remaining Term, the target performance bonus percentage of Base Salary shall be no less than the target performance bonus percentage of annual base salary of the Chief Executive Officer.

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(c)           Restricted Stock.  Upon Executive’s execution of the applicable Restricted Stock Agreement, Executive will receive shares of the Company’s service-based restricted stock as follows:  twenty thousand (20,000) shares with a one (1) year restriction period; thirty thousand (30,000) shares with a five (5) year restriction period.

(d)           Long-Term Incentive.  Prior to June 30, 2002, Company expects to adopt a new long-term incentive plan for officers.  Assuming such a plan is adopted, Executive will receive a participation valued at Five Million Dollars ($5,000,000), with such value to be determined on the same basis as for other senior executives.  In the event a new long-term incentive plan has not been implemented by June 30, 2002, Executive will be granted “phantom” stock options with a strike price of the fair market value of Company’s stock on June 30, 2002, and/or other equity-linked instruments, valued at Five Million Dollars ($5,000,000).  Executive’s participation in the long-term incentive plan or ownership of the phantom stock options (or other equity-linked instruments) will vest ratably over the Initial Term of this Agreement, commencing retroactively to January 2, 2002.  In the event of a “termination without cause” or a “resignation for good reason” provided by subparagraphs 7(d) and 7(e) of this Agreement, Executive will be deemed fully vested in the long-term incentive plan or ownership of the phantom stock options (or other equity-linked instruments).

(e)           Senior Executive Supplemental Plan.  For purposes of calculating Executive’s benefit under the Senior Executive Supplemental Plan, Company will credit Executive with seven (7) years of vesting service immediately upon hire.  Under this plan, Executive will earn five and one-half percent (5.5%) of average annual base pay plus average annual incentive for each year of service, to a maximum of fifty-five percent (55%) of pay.  Retirement eligibility under the Plan is age fifty-five (55) with ten (10) years’ service, or age

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sixty-two (62) with five (5) years’ service, and therefore Executive would be eligible to retire after three (3) years of service with a benefit of sixteen and one-half percent (16.5%) of pay.

4.             Benefits.  Executive shall be entitled to participate in all of the Company’s benefit plans on the same basis as other senior executives, including, but not limited to, the Company’s Flexible Benefits Plan (including health and dental coverage), Pension Equity Pension Plan, and an Employee Savings Plan with a 401(k) feature.  Executive shall also be provided the Supplemental Benefits and Perquisites set forth in Appendix A.

5.             Business Expenses.  Executive shall be entitled to prompt reimbursement for all reasonable expenses incurred by him in furtherance of Company’s business, in accordance with the policies and procedures established for senior executives of Company.

6.             Relocation Expenses.

To assist in Executive’s relocation to the Maryland area, Company will provide Executive with reimbursement for the following reasonable, documented costs:

House-hunting trips for Executive and/or Executive’s family

Settlement expenses for the sale of Executive’s current residence

Movement of Executive’s household goods, using a Company-approved moving company

Settlement expenses for the purchase of Executive’s new home

Reasonable temporary living expenses

Storage of Executive’s household goods for a reasonable period

Reasonable travel expenses from Illinois for Executive and his wife over a reasonable transition period

Ten Thousand Dollars ($10,000) incidental moving expenses

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To the extent that the reimbursement of any of these costs is subject to federal, state or local tax, the Executive shall be entitled to receive an additional payment (“a gross-up” payment) in an amount such that, after payment by the Executive of all taxes on such reimbursements, the Executive retains an amount of the gross-up payment equal to the tax imposed on the reimbursements.

7.             Termination.

(a)           Death.  Upon the death of Executive, this Agreement shall automatically terminate and Executive’s executor, administrator or designated beneficiary shall be entitled to receive the Executive’s Base Salary which shall have accrued to the date of such death and a pro rata portion of the performance bonus earned for that year under Company’s annual incentive plan.  For purposes of calculating the pro rata performance bonus, Executive will be deemed to have attained his individual performance goals at target.

(b)           Illness or Disability.  If Executive is absent from his employment for reasons of illness or other physical or mental incapacity for more than one hundred eighty (180) consecutive days, Company may terminate this Agreement and Executive’s employment hereunder.  In such event, Company shall be obligated to pay Executive his salary to the end of the month in which his employment is terminated, and a pro rata portion of the performance bonus earned for that year under Company’s annual incentive plan.  For purposes of calculating the pro rata performance bonus, Executive will be deemed to have attained his individual performance goals at target.

(c)           Termination for Cause.  Company may terminate this Agreement and Executive’s employment hereunder at any time for Cause.  “Cause” shall be defined in the same

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manner as it is defined by Section 1.7 of the Form of Severance Agreement dated December   , 2001, and attached hereto as Appendix B (“Severance Agreement”).  The procedures for effectuating a termination for Cause as set forth in Section 1.7 of the Severance Agreement shall be applicable.

In the event of termination for Cause, Company shall pay Executive his Base Salary up to the effective date of the termination.

(d)           Termination without Cause.  Notwithstanding anything contained herein to the contrary, Company also may terminate this Agreement and Executive’s employment hereunder for any reason whatsoever, upon thirty (30) days’ prior written notice to Executive.  In the event that Company terminates this Agreement other than for Cause, Executive shall be entitled to:  (i) Base Salary for the remainder of the Term of this Agreement; (ii) a performance bonus for each year remaining in the Term of this Agreement (prorated for partial years remaining) as if Executive and Company attained all performance goals at target; (iii) removal of the restriction for the twenty thousand (20,000) shares of Company stock with a one (1) year restriction period provided by Section 3(c) of this Agreement, without regard to whether the one (1) year period has elapsed; (iv) removal on a pro rated basis of the restriction for the thirty thousand (30,000) shares of Company stock with a five (5) year restriction period provided by Section 3(c) of the Agreement (e.g., if Executive is employed for two (2) full years, the restriction would be removed from 2/5 of the 5 year restricted stock; (v) immediate vesting of the Long-Term Incentive provided by Section 3(d) of this Agreement; and (vi) immediate vesting of all benefits under the Senior Executive Supplemental Plan provided by Section 3(e) of this Agreement (i.e., Executive will be eligible to retire at age 55 with a benefit of sixteen and one-half percent (16.5%) of pay (average annual base pay plus average annual incentive)).  In return

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for the separation benefits provided herein, Executive will execute a waiver releasing the Company and its affiliates from all claims related to his employment or the termination of his employment.

(e)           Resignation for Good Reason.  Executive may terminate this Agreement and Executive’s employment hereunder for Good Reason.  “Good Reason” shall be defined in the same manner as it is defined by Section 1.6 of the Form of Severance Agreement, except that the occurrence of a Change of Control will not be necessary for Executive to exercise his right to resign for Good Reason.  A termination of employment by the Executive for Good Reason shall be effectuated by giving the Company written notice (“Notice of Termination for Good Reason”) of the termination within six (6) months of the occurrence of the event constituting Good Reason or, if such event is not immediately recognizable by the Executive, within six (6) months of the date the Executive became or reasonably should have become aware of such event (but in no event beyond the expiration of the Term of this Agreement), setting forth in reasonable detail the specific conduct of the Company that constitutes Good Reason and the specific provision(s) of this Agreement on which the Executive relies.  A termination of employment by the Executive for Good Reason shall be effective on the thirtieth (30^th) day following the date when the Notice of Termination for Good Reason is given, unless the notice sets forth a later date (which date shall in no event be later than sixty (60) days after the notice is given); provided, however, that no event described hereunder shall constitute Good Reason if such event is a result of an isolated, insubstantial and inadvertent action that is not taken in bad faith and that is remedied by the Company within five (5) days after receipt of the Notice of Termination for Good Reason by the Company from the Executive.  The Executive’s continued employment shall not constitute consent to, or a waiver of rights with respect to, any act or failure to act constituting Good

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Reason hereunder.  In the event that Executive terminates this Agreement for Good Reason in accordance with the terms of this Agreement, Executive shall be entitled to: (i) Base Salary for the remainder of the Term of this Agreement; (ii) a performance bonus for each year remaining in the Term of this Agreement (prorated for partial years remaining) as if Executive and Company attained all performance goals at target; (iii) removal of the restriction for the twenty thousand (20,000) shares of Company stock with a one (1) year restriction period provided by Section 3(c) of this Agreement, without regard to whether the one (1) year period has elapsed; (iv) removal on a pro rated basis of the restriction for the thirty thousand (30,000) shares of Company stock with a five (5) year restriction period provided by Section 3(c) of the Agreement (e.g., if Executive is employed for two (2) full years, the restriction would be removed from 2/5 of the 5 year restricted stock); (v) immediate vesting of the Long-Term Incentive provided by Section 3(d) of this Agreement; and (vi) immediate vesting of all benefits under the Senior Executive Supplemental Plan provided by Section 3(e) of this Agreement (i.e., Executive will be eligible to retire at age 55 with a benefit of sixteen and one-half percent (16.5%) of pay (average annual base pay plus average annual incentive)).  In return for the separation benefits provided herein, Executive will execute a waiver releasing the Company and its affiliates from all claims related his employment or the termination of his employment.

(f)            Change of Control.  In the event of a Change in Control during the term of this Agreement, Executive shall be entitled to no less than the severance benefits provided by the Severance Agreement, the form of which is attached hereto as Exhibit B, regardless of whether said Severance Agreement is terminated or amended during such Term.  In no event shall the Executive be entitled to benefits under both this Agreement and the Severance Agreement or any other Company severance program.

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8.             Confidential Information and Discoveries.  Executive acknowledges that he will, as a result of his duties as an employee of Company, have access to and be in a position to receive confidential information.  Therefore, Executive agrees that during his employment by Company and thereafter he will not divulge to, or use for the benefit of, himself or any other person, any information concerning any inventions, discoveries, improvements, processes, methods, trade secrets, research or secret data (including, without limitation, computer programs, software development or executive systems), or other confidential matters possessed, owned or used by Company that may be obtained or learned by the Executive in the course of or as a result of his employment hereunder unless such disclosure is authorized in writing by the CEO.  The expiration or termination of employment shall not be deemed to release the Executive from his duties hereunder not to reveal or convert to his own use or the use of others the information described herein.

9.             Remedy.  Executive understands that Company would not have an adequate remedy at law for the material breach or threatened breach by Executive of the covenants set forth in Paragraph 8 of this Agreement and agrees that in the event of any such material breach or threatened breach, Company may, in addition to the other remedies which may be available to it, file a suit in equity to enjoin Executive from the breach or threatened breach of such covenant.

10.           Miscellaneous.

(a)           Notices.  Any notice required or permitted to be given under this Agreement shall be sufficient if in writing and if sent by registered or certified mail to Executive or Company at the address set forth below their signatures at the end of this Agreement or to such other address as they shall notify each other in writing.

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(b)           Assignment.  This Agreement shall be binding upon and inure to the benefit of Company and its successors and assigns.  This Agreement shall not be assignable by Executive.

(c)           Applicable Law.  This Agreement shall be construed in accordance with the laws of the State of Maryland in every respect, including, without limitation, validity, interpretation and performance.

(d)           Headings.  Section headings and numbers herein are included for convenience of reference only and this Agreement is not to be construed with reference thereto.  If there be any conflict between such numbers and headings and the text hereof, the text shall control.

(e)           Severability.  If for any reason any portion of this Agreement shall be held invalid or unenforceable, it is agreed that the same shall not affect the validity or enforceability of the remainder hereof.

(f)            Entire Agreement.  This Agreement, including its Appendices, contains the entire agreement of the parties with respect to its subject matter and supersedes all previous agreements between the parties.  No modification of this Agreement shall be valid unless made in writing and signed by the parties hereto.

(g)           Waiver of breach.  The waiver of Company or Executive of a breach of any provision of this Agreement by the other party shall not operate or be construed as a waiver of any subsequent breach.

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(h)           Counterparts.  This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original, but all of which together shall constitute one agreement.

CONSTELLATION ENERGY GROUP, INC.				MICHAEL J. WALLACE
By:	/S/		/S/
Its:	V.P., HR
Address:			Address:
Date:		12/20/01	Date:		12/20/01

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Exhibit 10(q)

Attachment 2

SEVERANCE AGREEMENT

This Agreement is made the     day of              , 2002, by and between CONSTELLATION ENERGY GROUP, INC. (the “Company”) and Michael J. Wallace (the “Executive”), and is effective as of       , 2002].

WHEREAS, the Company wishes to encourage the orderly succession of management in the event of a Change in Control (as hereinafter defined); and

WHEREAS, the Company desires to maintain a severance benefit for the Executive covering the period from the date of a Change in Control until the end of the twenty-four month period following the date of a Change in Control, to avoid the loss or the serious distraction of the Executive to the detriment of the Company and its stockholders prior to and during such period when the Executive’s undivided attention and commitment to the needs of the Company would be particularly important; and

WHEREAS, the Executive desires to devote the Executive’s time and energy for the benefit of the Company and its stockholders and not to be distracted as a result of a Change in Control.

                                NOW, THEREFORE, the parties agree as follows:

1.             Definitions.

1.1           Board. The term “Board” means the Board of Directors of the Company.

1.2           Change in Control. The term “Change in Control” means:

(i) the purchase or acquisition by any person, entity or group of persons (within the meaning of section 13(d) or 14(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), or any comparable successor provisions), of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20 percent or more of either the outstanding shares of common stock of the Company or the combined voting power of the Company’s then outstanding shares of voting securities entitled to a vote generally, or

(ii) the consummation of, following the approval by the Company’s stockholders of, a reorganization, merger or consolidation of the Company, in each case, with respect to

which persons who were stockholders of the Company immediately prior to such reorganization, merger or consolidation do not, immediately thereafter, own more than 50 percent of the combined voting power entitled to vote generally in the election of directors of the reorganized, merged or consolidated entity’s then outstanding securities, or

(iii) a liquidation or dissolution of the Company or the sale of substantially all of its assets, or

(iv) a change of more than one-half of the members of the Board within a 90-day period for reasons other than the death, disability, or retirement of such members.

1.3           Qualifying Termination.

(a)           The occurrence of any one or more of the following

events within twenty-four calendar months after the date of a Change in Control shall constitute a “Qualifying Termination”:

(i)            The Company’s termination of the Executive’s employment without Cause (as defined in Section 1.7); or

(ii)           The Executive’s resignation for Good Reason (as defined in Section 1.6).

(b)           A Qualifying Termination shall not include a termination of employment by reason of death, disability, the Executive’s voluntary termination of employment without Good Reason, or the Company’s termination of the Executive’s employment for Cause.

1.4           Ineligible to Retire.  Ineligible to Retire, means an Executive who has not met the eligibility requirements for retirement under any Company or Affiliate supplemental non-qualified pension plan in which the Executive participated immediately prior to the occurrence of a Qualifying Termination.

1.5           Eligible to Retire.  Eligible to Retire, means an Executive who has met the eligibility requirements for retirement under any Company or Affiliate supplemental non-qualified pension plan in which the Executive participated immediately prior to the occurrence of a Qualifying Termination.

                                1.6           Good Reason.  Good Reason means, without the Executive’s express written consent, the occurrence after the date of a Change in Control of any one or more of the following:

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(a)           The assignment to the Executive of duties materially inconsistent with the Executive’s authorities, duties, responsibilities, and status (including offices, title and reporting relationships) as an executive and/or officer of the Company or an Affiliate immediately prior to the date of the Change in Control, or a material reduction or alteration in the nature or status of the Executive’s authorities, duties, or responsibilities from those in effect immediately prior to the date of the Change in Control, (including as a type of such reduction or alteration for an Executive who is an officer of a publicly traded company immediately prior to the date of the Change in Control, the Executive occupying the same position or title but with a company whose stock is not publicly traded), unless such act is remedied by the Company or such Affiliate within 10 business days after receipt of written notice thereof given by the Executive; or

(b)           A reduction by the Company or an Affiliate of the Executive’s base salary in effect immediately prior to the date of the Change in Control or as the same shall be increased from time to time, unless such reduction is less than ten percent (10%) and it is either (i) replaced by an incentive opportunity equal in value; or is (ii) consistent and proportional with an overall reduction in management compensation due to extraordinary business conditions, including but not limited to reduced profitability and other financial stress (i.e., the base salary of the Executive will not be singled out for reduction in a manner inconsistent with a reduction imposed on other executives of the Company or such Affiliate); or

(c)           The relocation of the Executive’s office more than 50 miles from the Executive’s office immediately prior to the date of the Change in Control; or

(d)           Failure of the Company or an Affiliate (whichever is the Executive’s employer) to provide (i) the Executive the opportunity to participate in all applicable incentive, savings and retirement plans, practices, policies and programs of the Company or such Affiliate to the same extent as other senior executives (or, where applicable, retired senior executives) of the Company or such Affiliate, and (ii) the Executive and/or the Executive’s family, as the case may be, the opportunity to participate in, and receive all benefits under, all applicable welfare benefit plans, practices, policies and programs provided by the Company or such Affiliate, including, without limitation, medical, prescription, dental, disability, sick benefits, accidental death and travel insurance plans and programs, to the same extent as other senior executives (or, where applicable, retired senior executives) of the Company or such Affiliate; or

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(e)           Failure of the Company or an Affiliate (whichever is the Executive’s employer) to provide the Executive such perquisites as the Company or such Affiliate may establish from time to time which are commensurate with the Executive’s position and at least comparable to those received by other senior executives at the Company or such Affiliate; or

(f)            The failure by the Company to comply with paragraph (c) of Section 11 of this Agreement; or

(g)           Any other substantial breach of this Agreement by the Company that either is not taken in good faith or is not remedied by the Company promptly after receipt of notice thereof from the Executive.

The Executive’s right to terminate employment for Good Reason shall not be affected by the Executive’s incapacity due to physical or mental illness.  The Executive’s continued employment shall not constitute consent to, or a waiver of rights with respect to, any circumstance constituting Good Reason herein.  A termination of employment by the Executive for Good Reason for purposes of this Agreement shall be effectuated by giving the Company written notice (“Notice of Terminaton for Good Reason”) of the termination within six (6) months of the occurrence of the event constituting Good Reason or, if such event is not immediately recognizable by the Executive, within six (6) months of the date the Executive became or reasonably should have become aware of such event, setting forth in reasonable detail the specific conduct of the Company that constitutes Good Reason and the specific provision(s) of this Agreement on which the Executive relies.  A termination of employment by the Executive for Good Reason shall be effective on the thirtieth (30^th) day following the date when the Notice of Termination for Good Reason is given, unless the notice sets forth a later date (which date shall in no event be later than sixty (60) days after the notice is given); provided, however, that no event described hereunder shall constitute Good Reason if such event is a result of an isolated, insubstantial and inadvertent action that is not taken in bad faith and that is remedied by the Company within five (5) days after receipt of the Notice of Termination for Good Reason by the Company from the Executive.  If the Company disputes the existence of Good Reason, the burden of proof is on the Company to establish that Good Reason does not exist.

1.7              Cause.  Cause shall mean the occurrence of any one or more of the following:

(a)           The Executive is convicted of a felony involving moral turpitude; or

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(b)           The Executive engages in conduct or activities that constitutes disloyalty to the Company or an Affiliate and such conduct or activities are materially damaging to the property, business or reputation of the Company or an Affiliate; or

(c)           The Executive persistently fails or refuses to comply with any written direction of an authorized representative of the Company other than a directive constituting an assignment described in Section 1.6(a); or

(d)           The Executive embezzles or knowingly, and with intent, misappropriates property of the Company or an Affiliate, or unlawfully appropriates any corporate opportunity of the Company or an Affiliate.

A termination of the Executive’s employment for Cause for purposes of this Agreement shall be effected in accordance with the following procedures.  The Company shall give the Executive written notice (“Notice of Termination for Cause”) of its intention to terminate the Executive’s employment for Cause, setting forth in reasonable detail the specific conduct of the Executive that it considers to constitute Cause and the specific provision(s) of this Agreement on which it relies, and stating the date, time and place of the Board Meeting for Cause.  The “Board Meeting for Cause” means a meeting of the Board at which the Executive’s termination for Cause will be considered, that takes place not less than ten (10) and not more than twenty (20) business days after the Executive receives the Notice of Termination for Cause.  The Executive shall be given an opportunity, together with counsel, to be heard at the Board Meeting for Cause.  The Executive’s Termination for Cause shall be effective when and if a resolution is duly adopted at the Board Meeting for Cause by a two-thirds vote of the entire membership of the Board, excluding employee directors, stating that in the good faith opinion of the Board, the Executive is guilty of the conduct described in the Notice of Termination for Cause, and that conduct constitutes Cause under this Agreement.

                                1.8           Annual Award Amount.  The average of the two highest annual incentive awards under the Company’s annual incentive plan (or the annual cash incentive plan maintained by a successor company or an Affiliate) paid in the last five years to the Executive prior to the occurrence of the Qualifying Termination; provided, however, that if the Executive has not been employed by the Company or an Affiliate for a sufficient length of time to have been eligible for payment of at least two annual incentive awards, deemed target award payout shall be used for the one or two years for which the Executive was not so eligible.

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                                1.9.          Affiliate.  The term “Affiliate” means any company directly or indirectly controlling, controlled by or under common control with the Company or any successor company.

                                2.             Severance Benefits for an Executive Ineligible to Retire.  Upon the occurrence of a Qualifying Termination with respectto an Executive who is Ineligible to Retire:

                                (a)           Severance Payment. The Company shall pay to the Executive an amount equal to three times the Executive’s annual base salary (asin effect on the date of the Qualifying Termination, not reduced by any reduction described in Section 1.6(b) above) and Annual Award Amount.  The payment shall be made in a lump sum after the Qualifying Termination, and within approximately 10 business days after the Company receives the executed agreement referred to in 2(f) below but in no case prior to the expiration of any period during which the Executive is permitted to revoke such agreement.

                                (b)           Supplemental Retirement Benefits.  For purposes of determining the Executive’s supplemental retirement benefits which the Executive is entitled to under the Company’s supplemental non-qualified retirement plan in which the Executive participated immediately prior to the Qualifying Termination (or the supplemental retirement plan maintained by a successor company or an Affiliate), (i) the Executive’s age shall be deemed equal to the greater of (A) age 55 or (B) the Executive’s actual age, (ii) the Executive’s service percentage shall be deemed equal to 40%, and (iii) any minimum service eligibility requirements for such benefits shall be waived.

                                (c)           Severance Health Benefits.  The Company shall provide to the Executive the substantially equivalent value of the medical and dental benefits provided to active employees for three years after the Qualifying Termination and thereafter to any retiree of the Company or a successor or an Affiliate (whichever is the Executive’s employer) who has attained the deemed age and service used to compute supplemental retirement benefits in Section 2(b) above.

(d)           Split Dollar.  The Qualifying Termination shall not constitute a termination of any Split Dollar Agreement between the Company and the Executive (or the split dollar agreement between a successor company or an Affiliate and the Executive), and the Executive shall be deemed to have retired upon such Qualifying Termination for purposes of such Split Dollar Agreement (or the split dollar agreement between a successor company or an Affiliate and the Executive).

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(e)           Outplacement.  For a 60-day period commencing on the date of the Qualifying Termination, the Executive is entitled to receive outplacement services from one or more organizations that are offered by the Company from time to time, with such services capped at a Company cost of $50,000.

(f)            Release.  The benefits described in this Section 2 are payable by the Company to the Executive only if after the date of the Qualifying Termination, the Executive executes (and does not subsequently revoke) in writing and submits to the Company, in the form, manner, and subject to the timing established by the Company, an agreement releasing legal claims, including those against the Company and its Affiliates, including but not limited to claims arising out of the Executive’s Company or Affiliate employment or termination of such employment.

3.             Severance Benefits for an Executive Eligible to

Retire. Upon the occurrence of a Qualifying Termination with respect to an Executive who is Eligible to Retire:

                                (a)           Severance Payment. The Company shall pay to the Executive an amount equal to three times the Executive’s annual base salary (as in effect on the date of the Qualifying Termination, not reduced by any reduction described in Section 1.6(b) above) and Annual Award Amount.  The payment shall be made in a lump sum after the Qualifying Termination, and within approximately 10 business days after the Company receives the executed agreement referred to in 3(f) below but in no case prior to the expiration of any period during which the Executive is permitted to revoke such agreement.

                                (b)           Supplemental Retirement Benefits.  For purposes of determining the Executive’s supplemental retirement benefits which the Executive is entitled to under the Company’s supplemental non-qualified retirement plan in which the Executive participated immediately prior to the Qualifying Termination (or the supplemental retirement plan maintained by a successor company or an Affiliate), the Executive’s service percentage shall be deemed equal to 40% or the Executive’s actual service percentage (whichever is greater) and the Executive’s supplemental retirement benefit shall not be reduced for early receipt.

(c)           Severance Health Benefits.  The Company shall provide to the Executive the substantially equivalent value of the medical and dental benefits provided to active employees for three years after the Qualifying Termination and thereafter to any retiree of the Company or a successor company or an Affiliate (whichever is the Executive’s employer) who has attained age 65 and completed the greater of 20 years or actual years of service.

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(d)           Retirement.  The Executive shall be treated as having retired at the Company’s request for purposes of all of the Company’s benefit plans (or the benefit plans maintained by a successor company or an Affiliate (whichever is the Executive’s employer)).

(e)           Outplacement.  For a 60-day period commencing on the date of the Qualifying Termination, the Executive is entitled to receive outplacement services from one or more organizations that are offered by the Company from time to time, with such services capped at a Company cost of $50,000.

(f)            Release.  The benefits described in this Section 3 are payable by the Company to the Executive only if after the date of the Qualifying Termination, the Executive executes (and does not subsequently revoke) in writing and submits to the Company, in the form, manner, and subject to the timing established by the Company, an agreement releasing legal claims, including those against the Company and its Affiliates, including but not limited to claims arising out of the Executive’s Company or Affiliate employment or termination of such employment.

4.             Non-Exclusivity of Rights.  Nothing in this Agreement shall prevent or limit the Executive’s continuing or future participation in any plan, program, policy or practice provided by the Company or a successor company or an Affiliate (whichever is the Executive’s employer) for which the Executive may qualify, nor shall anything in this Agreement limit or otherwise affect such rights as the Executive may have under any contract or agreement with the Company or a successor Company or such Affiliate.  However, if the Executive receives severance benefits under this Agreement, the Executive is not also entitled to any benefit under any other severance plan, program, arrangement or agreement maintained by the Company or an Affiliate.  Vested benefits and other amounts that the Executive is otherwise entitled to receive under any incentive compensation (including, but not limited to any restricted stock or stock option agreements), deferred compensation and other benefit programs listed in Section 1.6(d), life insurance coverage, or any other plan, policy, practice or program of, or any contract or agreement with, the Company or a successor Company or such Affiliate on or after the date of the Qualifying Termination shall be payable in accordance with the terms of each such plan, policy, practice, program, contract or agreement, as the case may be, except as explicitly modified by this Agreement.

5.             Full Settlement.  The Company’s obligation to make the payments provided for in, and otherwise to perform its obligations under, this Agreement shall not be affected by any

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set-off, counterclaim, recoupment, defense or other claim, right or action that the Company may have against the Executive or others.  In no event shall the Executive be obligated to seek other employment or take any other action by way of mitigation of the amounts payable to the Executive under any of the provisions of this Agreement and, such amounts shall not be reduced, regardless of whether the Executive obtains other employment.

6.             Certain Additional Payments by the Company.

(a)           Anything in this Agreement to the contrary notwithstanding, in the event it shall be determined that any payment or distribution by the Company to or for the benefit of the Executive (a “Payment”) would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code of 1986, as amended (the “Code”) or any interest or penalties are incurred by the Executive with respect to such excise tax (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the “Excise Tax”), then the Executive shall be entitled to receive an additional payment (a “Gross-Up Payment”) in an amount such that after payment by the Executive of all taxes (including any interest or penalties imposed with respect to such taxes), including, without limitation, any income taxes (and any interest and penalties imposed with respect thereon) and Excise Tax imposed upon the Gross-Up Payment, the Executive retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Payments.

                                (b)           Subject to the provisions of paragraph (c) of this Section 6, all determinations required to be made under this Section 6, including whether and when a Gross-Up Payment is required and the amount of such Gross-Up Payment and the assumptions to be utilized in arriving at such determination, shall be made by one of the major internationally recognized certified public accounting firms (commonly referred to, as of the date hereof, as a Big Five firm) designated by the Executive and approved by the Company (which approval shall not be unreasonably withheld) (the “Accounting Firm”), which shall provide detailed supporting calculations both to the Company and the Executive within fifteen (15) business days of the receipt of notice from the Executive that there has been a Payment, or such earlier time as is requested by the Company.  In the event that the Accounting Firm is serving as accountant or auditor for the individual, entity or group affecting the change of control, the Executive shall designate another Big Five accounting firm (subject to the approval of the Company, which approval shall not be unreasonably withheld) to make the determinations required hereunder (which accounting firm shall then be referred to as the Accounting Firm hereunder).  All fees and expenses of the Accounting Firm shall be borne solely by the Company.  Any Gross-

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Up Payment, as determined pursuant to this Section 6, shall be paid by the Company to the Executive within five (5) days of the receipt of the Accounting Firm’s determination.  Any determination by the Accounting Firm shall be binding upon the Company and the Executive.  As a result of the uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Accounting Firm hereunder, it is possible that Gross-Up Payments which will not have been made by the Company should have been made (“Underpayment”) consistent with the calculations required to be made hereunder.  In the event that the Company exhausts its remedies pursuant to paragraph (c) of this Section 6 and the Executive thereafter is required to make a payment of any Excise Tax, the Accounting Firm shall determine the amount of the Underpayment that has occurred and any such Underpayment shall be promptly paid by the Company to or for the benefit of the Executive.

(c)           The Executive shall notify the Company in writing of any claim by the Internal Revenue Service that, if successful, would require the payment by the Company of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later than ten (10) business days after the Executive is informed in writing of such claim and shall apprise the Company of the nature of such claim and the date on which such claim is requested to be paid.  The Executive shall not pay such claim prior to the expiration of the thirty (30) day period following the date on which the Executive gives such notice to the Company (or such shorter period ending on the date that any payment of taxes with respect to such claim is due).  If the Company notifies the Executive in writing prior to the expiration of such period that it desires to contest such claim, the Executive shall:

(i)            give the Company any information reasonably requested by the Company relating to such claim,

(ii)           take such action in connection with contesting such claim as the Company shall reasonably request in writing from time to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company,

(iii)          cooperate with the Company in good faith in order effectively to contest such claim, and

(iv)          permit the Company to participate in any proceedings relating to such claim;

PROVIDED, however, that the Company shall bear and pay directly all costs and expenses (including additional interest and

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penalties) incurred in connection with such contest and shall indemnify and hold the Executive harmless, on an after-tax basis, for any Excise Tax or income tax (including interest and penalties with respect thereto) imposed as a result of such representation and payment of costs and expenses.  Without limitation on the foregoing provisions of this paragraph (c) of Section 6, the Company shall control all proceedings taken in connection with such contest and, at its sole option, may pursue or forego any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct the Executive to pay the tax claimed and sue for a refund or contest the claim in any permissible manner, and the Executive agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company shall determine; PROVIDED, however, that if the Company directs the Executive to pay such claim and sue for a refund, the Company shall advance the amount of such payment to the Executive, on an interest-free basis and shall indemnify and hold the Executive harmless, on an after-tax basis, from any Excise Tax or income tax (including interest or penalties with respect thereto) imposed with respect to such advance or with respect to any imputed income with respect to such advance; and PROVIDED, further, that any extension of the statute of limitations relating to payment of taxes for the taxable year of the Executive with respect to which such contested amount is claimed to be due is limited solely to such contested amount.  Furthermore, the Company’s control of the contest shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Executive shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority.

(d)           If, after the receipt by the Executive of an amount advanced by the Company pursuant to paragraph (c) of this Section 6, the Executive becomes entitled to receive any refund with respect to such claim, the Executive shall promptly take all necessary action to obtain such refund and (subject to the Company’s complying with the requirements of paragraph (c) of this Section 6) upon receipt of such refund shall promptly pay to the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto).  If after the receipt by the Executive of an amount advanced by the Company pursuant to paragraph (c) of this Section 6, a determination is made that the Executive shall not be entitled to any refund with respect to such claim and the Company does not notify the Executive in writing of its intent to contest such denial of refund prior to the expiration of thirty (30) days after such determination, then such advance shall be forgiven and

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shall not be required to be repaid and the amount of such advance shall offset, to the extent thereof, the amount of Gross-Up Payment required to be paid.

7.             Termination of Agreement.  This Agreement shall remain in effect from the date hereof until the last day of the twenty-fourth calendar month following the date of a Change in Control.  Further, upon the date of a Change in Control, this Agreement shall continue until the Company or its successor shall have fully performed all of its obligations thereunder with respect to the Executive, with no future performance being possible.  Notwithstanding the foregoing, this Agreement may be terminated by the Board at any time prior to the date of a Change in Control.

8.             Amendment of Agreement.  This Agreement may be amended by the Board at any time prior to the date of a Change in Control.  At and after the date of a Change in Control, this Agreement may not be amended in any respect without the written consent of the Executive.

9.             Construction.  Wherever any words are used herein in the masculine gender they shall be construed as though they were also used in the feminine gender in all cases where they would so apply, and wherever any words are used herein in the singular form, they shall be construed as though they were also used in the plural form in all cases where they would so apply.

10.           Governing Law.  This Agreement shall be governed by the laws of Maryland.

11.           Successors and Assigns.

(a)           This Agreement shall inure to the benefit of and be enforceable by the Executive’s legal representatives.

(b)           This Agreement shall inure to the benefit of and be binding upon the Company and its successors and assigns.

(c)           The Company shall require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company expressly to assume and agree to perform this Agreement in the same manner and to the same extent that the Company would have been required to perform it if no such succession had taken place.  As used in this Agreement, “Company” shall mean both the Company as defined above and any such successor that assumes and agrees to perform this Agreement, by operation of law or otherwise.

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12.           Indemnification.  The Company will pay all reasonable fees and expenses, if any, (including, without limitation, legal fees and expenses) that are incurred by the Executive to enforce this Agreement and that result from a breach of this Agreement by the Company.

13.           Notice.  Any notices, requests, demands, or other communications provided for by this Agreement shall be sufficient if in writing and if sent by registered or certified mail to the Executive at the last address the Executive has filed in writing with the Company, or in the case of the Company, to its principal offices.

14.           Severability.  The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement.  If any provision of this Agreement shall be held invalid or unenforceable in part, the remaining portion of such provision, together with all other provisions of this Agreement, shall remain valid and enforceable and continue in full force and effect to the fullest extent consistent with law.

15.           Withholding. Notwithstanding any other provision of this Agreement, the Company may withhold from amounts payable under this Agreement all federal, state, local and foreign taxes that are required to be withheld by applicable laws or regulations.

16.           Entire Agreement. Unless otherwise specifically provided in this Agreement, the Executive and the Company acknowledge that this Agreement supersedes any other agreement between them or between the Executive and the Company or an Affiliate, concerning the subject matter hereof.

17.           Alienability.  The rights and benefits of the Executive under this Agreement may not be anticipated, alienated or subject to attachment, garnishment, levy, execution or other legal or equitable process except as required by law.  Any attempt by the Executive to anticipate, alienate, assign, sell, transfer, pledge, encumber or charge the same shall be void.  Payments hereunder shall not be considered assets of the Executive in the event of insolvency or bankruptcy.

18.           Counterparts.  This Agreement may be executed in several counterparts, each of which shall be deemed an original, and said counterparts shall constitute but one and the same instrument.

IN WITNESS WHEREOF, the Executive has hereunto set the Executive’s hand and, pursuant to the authorization of the Board,

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the Company has caused this Agreement to be executed in its name on its behalf, all as of the day and year first above written.

CONSTELLATION ENERGY GROUP, INC.

By:

Michael J. Wallace

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EX-10.(R)

Exhibit 10(r)

Attachment 1

March 28, 2001

Mr. Thomas Brooks

216 Woodlawn Road

Baltimore, MD 21210

Dear Tom:

Confirming our recent conversation, Constellation Energy Group, Inc. (CEG) is  pleased to offer you employment in the position of Vice President, Business Development at an annual starting salary of $250,000 ($20,833 per month).  In addition, you will be eligible to participate in the company’s annual incentive plan, which provides for a bonus based upon your performance and the company’s results for the year.

We are also pleased to offer you a hiring incentive payment of  $1,000,000, which will be paid to you if you remain employed by CEG until the earlier of December 31, 2001 or the effective date of the spin-off of new Constellation Energy Group (“Spin off”), or if you are terminated without cause.  This payment will be made to you within 12 months following your date of hire.  If you resign from CEG after you are paid the hiring incentive and within one year after the effective date of your employment with CEG, you must reimburse CEG for the prorated amount of this hiring incentive (i.e., you earn the incentive ratably over the first 12 months of your employment with CEG). The level of incentive payment assumes you agree to join CEG promptly.

In addition to the above cash compensation, you will receive an award of not less than 10,000 shares of current CEG restricted stock from the CEG 2000-2002 Long-Term Incentive Plan, a copy of which is available for your review.  It is intended that this Plan be terminated prior to the Spin off. These shares will not be prorated when they are distributed at the time of the Spin-off.  You will also be eligible for a stock option grant from the new Constellation Energy Group Incentive Plan after the effective date of the Spin-off.  We expect to grant you not less than 150,000 options with a strike price of fair market value immediately after the Spin-off.  These options will vest over three years, with a ten-year exercise period.  It is possible that we may alter the proposed stock option plan to include restricted stock in new CEG that would be granted immediately after the Spin-off.  Should that occur, you will receive one share of new CEG restricted stock for each three options after the Spin-off.

As a member of senior management, you are also entitled to certain supplemental benefits and perquisites, shown on the attached summary.  These benefits and perquisites are subject to change at any time, at management’s discretion.

Your employment is at will.  While this document is not intended to constitute an employment contract, we will soon discuss the proposed terms of an employment agreement, including appropriate change in control provisions to address potential long-

term incentive compensation opportunity loss.  It is intended that new CEG equity awards include standard provisions regarding change of control protections.

This offer is contingent upon your passing the company’s pre-employment drug screening, your ability to meet employment eligibility requirements, and completion of a medical questionnaire.  We will also require you to sign the enclosed confidentiality agreement covering your employment with CEG.

We are looking forward to your joining Constellation Energy Group.  If you have any questions, feel free to contact me or Eric Grubman.

Very truly yours,

/S/

Janet E. McHugh

Vice President-Human Resources

I acknowledge and accept the terms and conditions set forth in this offer letter.

/S/	4/6/01
Signature	Date

Exhibit 10(r)

Attachment 2

April 6, 2001

Mr. Thomas V. Brooks

216 Woodlawn Road

Baltimore, MD  21210

Dear Tom;

You have represented your Goldman Sachs equity position (your “GS Equity”) in Schedule A attached.  For purposes of this agreement, the total current value of the GS Equity is deemed to be $3.0 million.

Constellation Energy Group, Inc. (“CEG”) agrees to the following:

1.             During April 1, 2001 to March 31, 2003:

If CEG or new Constellation Energy Group (after the spin-off of CEG’s merchant energy business) (“GENCO”), at which you’re employed (“Employer”) undergoes a change-of-control and your employment is Terminated, Employer will pay you the difference between $3.0 million and the then-current Value of the GS Equity in which you are vested as of the date of such Termination (the “Sum”). This obligation of Employer is relieved if you retain your rights to receive your GS Equity following a change-of-control.  For purposes of this letter, Terminated shall mean your employment is terminated by Employer without Cause (as defined in the CEG Supplemental Pension Plan or any successor plan) or your duties are diminished in a material manner.  Additionally, if Employer terminates your employment without Cause (regardless of whether a change of control has occurred), Employer will pay you the Sum. This obligation of Employer is relieved if you retain your rights to receive your GS Equity following such termination.

2.             After March 31, 2003:

If you voluntarily terminate your employment with Employer, or you are Terminated without Cause, Employer will pay you the Sum. This obligation of Employer is relieved if you retain your rights to receive your GS Equity following such termination or Termination.

This obligation of Employer may be assigned at Employer’s option to any related or successor entity at which you become employed.

For purposes of this letter, the Value of GS Equity shall be calculated using the average closing price of Goldman Sachs common stock for the 10 trading days immediately preceding the event which gives rise to the need to calculate such Value.  Common stock or common stock equivalents shall be valued at that price.  Options or option equivalents shall be valued using the difference between the strike price and such average closing price of the common stock.  Negative values shall be valued at zero.

Page 2

Thomas V. Brooks

April 6, 2001

Notwithstanding the previous stipulations, (i) if you commit any action or behavior which relieves Goldman Sachs of its obligation to deliver any or all of the GS Equity, other than the actions or events herein described, or (ii) after your GS Equity becomes vested, Employer shall be relieved of its obligations hereunder; provided, that Employer shall not be so relieved if after your reasonable demand, Goldman Sachs fails to deliver any or all of the GS Equity due to actions taken by you in your capacity as an employee of Employer and that are within in the scope of your employment duties with Employer.

At any time following the date of this letter, if the vested GS Equity (whether delivered or not) to which you become entitled after the date of this letter exceeds a Value of $3.0 million, Employer is relieved of any further obligation regardless of whether you have chosen to sell the GS Equity or otherwise realize or hedge such value, in whole or in part.

Sincerely,

/S/

Eric P. Grubman

Attachment

Exhibit 10(r)

Attachment 3

[CONSTELLATION ENERGY GROUP LOGO]

Human Resources Division

Vice President’s Office

Memo

To:          Thomas V. Brooks

From:     Elaine Johnston

Date:      December 4, 2001

Re:          Retention Plan Summary

1.             2001 Annual Bonus Guarantee

•Guarantee of $1,500,000 to be paid to you in the first quarter 2002, assuming you are employed by CEG at the time of payment.  This amount will be paid in cash and is subject to AIP deferral elections and required tax withholding.

2.             Stock Option Grant

•Grant 150,000 CEG stock options (non-qualified stock options) under the 1995 Long-Term Incentive Plan at fair market value on grant date (November 12, 2001). Exercise price is $25.08

•               Options vest 40% on July 1, 2002 and 60% on July 1, 2003

•Exercise period 10 years from grant date

•Vested options exercisable until earlier of (1) end of exercise period or (2) termination date (if not leaving due to retirement, long-term disability or death)

•               Unvested options are forfeited at termination date

•Upon a change in control, as defined in the 1995 Long-Term Incentive Plan, granted options would vest immediately

Note: A stock option agreement outlining the specific provisions of the grant will be forthcoming.

3.             Retention Cash Payments

•Provide total cash amount of $1,150,000; 40% to vest July 1, 2002 and 60% to vest July 1, 2003, provided you remain employed by CEG until the respective vesting date.  This amount will be paid in cash within 30 days of the respective vesting date and is subject to required tax withholding.

•Upon a change in control, as defined in the 1995 Long-Term Incentive Plan, any unvested amount would vest and payment would be made.

Upon a termination of your employment by the company without cause, your unvested retention cash payments and stock options will immediately vest, and the options will remain exercisable during the original exercise period.  “Cause” means that you (i) engage in conduct or activities that constitutes disloyalty to the company or any affiliate and that is damaging to the property, business or reputation of the company or any affiliate; (ii) persistently fail or refuse to comply with any written direction of an

authorized representative of the company; (iii) fail to perform satisfactorily duties that would reasonably be expected of someone in your position; (iv) embezzle or knowingly, and with intent, misappropriate property of the company or an affiliate, or unlawfully appropriate any corporate opportunity of the company or an affiliate; or (v) are convicted of a felony.

Signed:

EX-10.(S)

Exhibit 10(s)

AGREEMENT, RELEASE AND WAIVER

This Agreement, Release and Waiver (“Agreement”) is entered into by and between Eric P. Grubman (“Grubman”) and Constellation Energy Group, Inc. (“Company”).

1.             In consideration of Grubman’s provision of certain waivers as set forth in this Agreement in connection with his voluntary resignation from employment with the Company effective December 1, 2001, the Company agrees to provide to Grubman (a) a $2,075,000 lump sum cash payment payable on or before the 8^th day following Grubman’s execution of this Agreement provided Grubman has not revoked the Agreement as set forth in paragraph 15; (b) access to secretarial support from Janice Sawyer until December 31, 2001; (c) reimbursement (subject to gross-up for payroll tax withholding) for the following expenses incurred and paid by Grubman (i) lease expense on 100 Harborview Apt. PH-2D from September 1, 2001 until December 31, 2001, (ii) rental expense from September 1, 2001 until December 31, 2001 for furniture at the apartment in (i),  (iii) real estate commission on the sale of one of Grubman’s Baltimore area residential dwellings if such dwelling is sold before March 31, 2002, such commission reimbursement not to exceed $20,000, and (iv) moving and storage expenses related to any move out of the apartment in (i) incurred on or before December 31, 2002; (d) reimbursement for moving and storage expenses incurred before June 15, 2002 related to any move out of Grubman’s office at 250 West Pratt Street; (e) up to 18 monthly cash payments of $584.95 commencing on or before January 15, 2002 (subject to gross-up for payroll taxes) toward the cost of health coverage, which monthly cash payments approximate on an after-tax basis the monthly premium cost of medical and dental coverage for Grubman as if he were an active employee and which shall cease effective on the date Grubman is eligible for health coverage through another employer; (f) maintenance by the Company until December 31, 2002 of Grubman’s memberships for any clubs for which Company paid Grubman’s membership fees as of November 30, 2001.  The foregoing consideration is over and above any benefits to which Grubman will be entitled under the Company’s benefit plans and policies as a result of his resignation from employment with the Company effective December 1, 2001, which benefits both parties acknowledge are set forth in Attachment A.

2.             The Company hereby agrees to provide the benefits set forth in paragraph 1 to Grubman from the Company’s general assets, and where applicable in accordance with the terms of the referenced benefit plans.  Except as set forth in the applicable benefit plans, such amounts set forth in paragraph 1 are not subject to alienation, assignment, attachment, garnishment or other legal process by or on behalf of Grubman until such amounts are actually received by him.  Such payments are subject to applicable payroll tax withholding and will not be considered as compensation for purposes of the Company’s retirement or welfare benefit plans.

3.             In exchange for the Company’s agreement to provide the consideration set forth in paragraph 1, Grubman knowingly, freely and voluntarily agrees that, to the full extent the law permits, he hereby releases and discharges the Company and any company controlling, controlled by or under common control with the Company (“Affiliate”), their successors, officers, directors, agents, representatives or employees from any and all debts, obligations, claims, demands, judgments or causes of action of any kind whatsoever, known or unknown, in tort, by statute or

on any other basis, for equitable relief, compensatory, punitive or other damages, expenses (including attorneys’ fees), and/or reimbursements of costs of any kind, including, but not limited to any and all claims, demands, rights and/or causes of action which might arise out of allegations relating to a claimed breach of contract (express or implied), or any tort, legal actions under Title VII of the Civil Rights Act of 1964, as amended (42 U.S.C. § 2000e et seq.), the Civil Rights Act of 1866 and 1871 (42 U.S.C. §§ 1981 and 1983), the Americans with Disabilities Act (42 U.S.C. § 12101 et seq.), the Age Discrimination in Employment Act (29 U.S.C. § 621 et seq.), the Equal Pay Act (29 U.S.C. § 206(d)(1)), the Rehabilitation Act (29 U.S.C. §§ 701-704), Executive Order 11246, or any other Federal, State, local or common law concerning age, gender, race, religion, national origin, disability or any other protected classification or category which expressly or impliedly may form the basis of alleged discrimination, or any other law or regulation.  To the extent any such actions are pending, Grubman agrees that they are or will be immediately withdrawn before or upon his commencement of receipt of the consideration set forth in paragraph 1.  Grubman also knowingly and voluntarily agrees that, to the full extent the law permits, he waives any and all causes of action and will not file, cause to be filed, or voluntarily assist in the prosecution of any charges, claims, lawsuits, or other actions of any kind against the Company, its Affiliates and/or or their successors, officers, directors, agents, representatives or employees.  Grubman is not waiving claims that may arise based on events occurring after he executes this Agreement, and is not waiving rights to enforce this Agreement.  Grubman further acknowledges that he expressly waives any right with respect to and forfeits any equity grant made at any time to him by the Company and any other remuneration or benefits not expressly set forth in paragraph 1 and Attachment A.   Notwithstanding anything in this Agreement to the contrary, Company acknowledges that Grubman’s right to indemnification under Company by-laws, charter, and coverage under any Director’s and Officer’s insurance, for acts and omissions incurred while Grubman was an employee of Company, is not waived by Grubman under this Agreement.

Additionally, Grubman does specifically, knowingly and voluntarily waive any and all rights or claims he may have under the Age Discrimination in Employment Act (ADEA).

Subject to paragraphs 6, 7, 8, 9, and 10, Company releases and discharges Grubman from all debts, obligations, claims, demands judgments or causes of action of any kind whatsoever, known or unknown, in tort, by statute or on any other basis, for equitable relief, compensatory, punitive or other damages, expenses (including attorneys’ fees), and/or reimbursements of costs of any kind, including, but not limited to any and all claims, demands, rights and/or causes of action which might arise out of allegations relating to a claimed breach of contract (express or implied), or any tort. To the extent any such actions are pending, Company agrees that they are or will be immediately withdrawn before or upon the expiration of the 7-day period in paragraph 15.  Company also agrees that, to the full extent the law permits, it waives any and all causes of action and will not file, cause to be filed, or voluntarily assist in the prosecution of any charges, claims, lawsuits, or other actions of any kind against Grubman.  Company is not waiving claims that may arise based on events occurring after it executes this Agreement.

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4.             Nothing in this Agreement, including the payment of any sum by the Company, constitutes an admission by the Company or any Affiliate of any legal wrong.

5.             The parties agree that the terms of this Agreement including the consideration set forth in paragraph 1 are confidential and will not be disclosed to any non-parties hereto; provided, however, that Grubman may disclose such information to his spouse, personal attorney, and personal accountant and financial advisors, and otherwise as required by law or order of a court.  Should Grubman wish to consult with anyone else he deems appropriate to review this Agreement, he must first obtain the written consent of the Company which will not be unreasonably withheld.  In addition, the Company may disclose such information as is necessary, in its sole discretion, to federal or state agencies or to comply with any law.

6.             Grubman acknowledges that while he was an active employee of the Company or any Affiliate, he received or had access to confidential and proprietary information which is a valuable, special and unique asset of the Company and/or its Affiliates.  Accordingly, Grubman agrees that, for a period of one year from the date of this Agreement (noted in the final sentence of this Agreement), he shall not (directly or indirectly) divulge or communicate to any person (except as compelled by order of a court of competent jurisdiction if Grubman provides the Company with notice at least 10 business days before complying with such order, to provide the Company the opportunity to challenge the order), confidential commercial information, or any other business or commercial information, or data of the Company, its customers, or any Affiliates, which is not generally known to the public.

Grubman further agrees that he will, as soon as reasonably practicable following his resignation from employment with the Company, return to the Company all Company and Affiliate property, as well as all books, records, customer and pricing lists, correspondence, contracts or orders, advertising or promotional materials, and other written, typed or printed materials, whether furnished by the Company or prepared by Grubman, which contain any information relating to the Company’s business, and Grubman agrees that he will neither make nor retain copies of such materials; provided, however, that any correspondence prepared by or addressed to Grubman may be retained by Grubman subject to Grubman’s obligation not to disclose confidential information as set forth in this paragraph 6.

7.             Grubman agrees to refrain from making any untruthful oral or written statements to the public, or to any third party, about the Company or its Affiliates, their business practices, or the business practices of any present or former officers, directors, executives, employees, representatives, agents or customers or any related services of the Company, or any general matter concerning the Company or any of its Affiliates’ reputation, standing in the business community, or business practices.    Company agrees to refrain from making any untruthful oral or written statements to the public, or to any third party, about Grubman, his reputation, standing in the business community, or business practices.

8.             Grubman agrees that prior to July 1, 2002, he will not directly or indirectly, whether or not for compensation and whether or not as an employee, be engaged in or have any financial interest in  certain entities as reasonably requested by the Company and agreed to by Grubman in writing.  For purposes of this Agreement, Grubman shall be deemed to be engaged

3

in or have a financial interest in such entity  if he is an employee, officer, director, member, principal or partner, of such entity, or if he directly or indirectly performs services for such entity or if he or any member of his immediate family beneficially owns an equity interest, or interest convertible into equity, in any such entity; provided, however, that the foregoing shall not prohibit Grubman or a member of his immediate family from owning, for the purpose of passive investment, less than 5% of any class of securities of a publicly held corporation.

9.             Prior to July 1, 2002, Grubman will not, directly or indirectly, either as a proprietor, stockholder, partner, principal, officer, employee, consultant, advisor or otherwise, personally induce or entice any employee of the Company or an Affiliate to leave such employ; provided, however, that Grubman will not be precluded from hiring any such employee who he has not so induced or enticed.

10.           In the event of a breach or threatened breach by Grubman of the provisions of paragraphs 6, 7, 8, or 9 of this Agreement, Grubman agrees that the Company will be authorized and entitled to obtain, from any court of competent jurisdiction, an injunction restraining Grubman from such breach and from rendering any services to any person, firm, or entity in breach of such paragraphs.  Nothing in this Agreement shall be construed as prohibiting the Company from pursuing any other remedies available to it for a breach or threatened breach of paragraphs 6, 7, 8, or 9.

11.           In the event any provision of paragraphs 6, 7, 8, or 9  of this Agreement is held to be an unreasonable restriction upon Grubman, the court so holding may reduce the territory to which it pertains and/or the period of time in which it operates, or order any other change to the extent necessary to render such provision enforceable.

12.           If it is determined by a court of competent jurisdiction that Grubman has failed to comply with one or more terms of this Agreement, the damages, if any, which the Company may receive from him shall not exceed, in the aggregate, the value of the payments described in paragraph 1.

13.           Grubman acknowledges that the Company has advised him to consult with an attorney prior to executing this Agreement.

14.           Grubman acknowledges that he has a period of at least twenty-one (21) calendar days to consider this Agreement.  Grubman further acknowledges that if this Agreement, signed by him, is not received by the Vice President of Human Resources, Constellation Energy Group, Inc., 24^th Floor, 250 West Pratt Street, Baltimore, Maryland 21201, on or before December 24, 2001, this Agreement is null and void and unenforceable by the parties, and Grubman will not be entitled to the consideration set forth in paragraph 1.

15.           Grubman acknowledges that he has been specifically informed by the Company that for a period of seven (7) calendar days following the date of his execution of this Agreement (as indicated in the last paragraph of this Agreement) he has the absolute right to revoke this

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Agreement by notifying Vice President of Human Resources, Constellation Energy Group, Inc., in writing on or before the expiration of the seven (7) day period.

16.           This Agreement shall not become effective or enforceable until the aforesaid seven (7) calendar day revocation period has expired.

17.           This Agreement supersedes any and all other agreements or proposals, written or oral, made by the Company or any Affiliate, or on their behalf to Grubman, and this Agreement is the full and final understanding between the parties; provided, however that any written document designating an entity referenced in paragraph 8 shall be deemed a part of this Agreement.

18.           The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.  This Agreement may only be modified by a written agreement signed by the parties.

19.           This Agreement shall be governed by the laws of Maryland.

20.           Grubman does hereby acknowledge that he has read and understands this Agreement.

21.           Grubman does hereby acknowledge that he has signed this Agreement freely and voluntarily.

IN WITNESS WHEREOF, Eric P. Grubman does hereby execute this Agreement on this         day of December, 2001.

		(Seal)
	Eric P. Grubman
Received and accepted by:	CONSTELLATION ENERGY GROUP,
	INC.
	By:	(Seal)
	Name: Mayo A. Shattuck III
	Title:  President and Chief Executive Officer

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Benefits

Health and dental benefit COBRA coverage.

Ability to convert employee life insurance coverage to an individual policy.

Ability to convert disability insurance coverage to an individual policy.

Payout for unused vacation.

Tax and estate planning services rendered through December 1, 2001.

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EX-12.(A)

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EXHIBIT NO. 12(a)

CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

		12 Months Ended
		December 2001		December 2000		December 1999		December 1998		December 1997
		(In Millions of Dollars)
Income from Continuing Operations (Before Extraordinary Loss and Cumulative Effect of Change in Accounting Principle)		$	82.4	$	345.3	$	326.4	$	305.9	$	254.1
Taxes on Income, Including Tax Effect for BGE Preference Stock Dividends			29.7		221.4		182.5		169.3		145.1
Adjusted Income		$	112.1	$	566.7	$	508.9	$	475.2	$	399.2
Fixed Charges:
	Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness	$	226.1	$	261.5	$	245.7	$	255.3	$	234.2
	Earnings Required for BGE Preference Stock Dividends		21.4		21.9		21.0		33.8		45.1
	Capitalized Interest		55.8		21.1		2.7		3.6		8.4
	Interest Factor in Rentals		2.0		2.2		1.8		1.9		1.9
	Total Fixed Charges	$	305.3	$	306.7	$	271.2	$	294.6	$	289.6
Earnings(1)		$	361.6	$	852.3	$	777.4	$	766.2	$	680.4
Ratio of Earnings to Fixed Charges			1.18		2.78		2.87		2.60		2.35

(1)

Earnings are deemed to consist of income from continuing operations (before extraordinary loss and cumulative effect of change in accounting principle) 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 other than capitalized interest.

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CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

EX-12.(B)

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EXHIBIT NO. 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

		12 Months Ended
		December 2001		December 2000		December 1999		December 1998		December 1997
		(In Millions of Dollars)
Income from Continuing Operations (Before Extraordinary Loss)		$	97.3	$	143.5	$	328.4	$	327.7	$	282.8
Taxes on Income			60.3		94.2		182.0		181.3		161.5
Adjusted Income		$	157.6	$	237.7	$	510.4	$	509.0	$	444.3
Fixed Charges:
	Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness	$	158.8	$	186.8	$	206.4	$	255.3	$	234.2
	Capitalized Interest		—		—		0.4		3.6		8.4
	Interest Factor in Rentals		0.7		0.9		1.0		1.9		1.9
	Total Fixed Charges	$	159.5	$	187.7	$	207.8	$	260.8	$	244.5
Preferred and Preference
	Dividend Requirements:(1)
	Preferred and Preference Dividends	$	13.2	$	13.2	$	13.5	$	21.8	$	28.7
	Income Tax Required		8.2		8.7		7.5		12.0		16.4
	Total Preferred and Preference Dividend Requirements	$	21.4	$	21.9	$	21.0	$	33.8	$	45.1
Total Fixed Charges and Preferred and Preference Dividend Requirements		$	180.9	$	209.6	$	228.8	$	294.6	$	289.6
Earnings(2)		$	317.1	$	425.4	$	717.8	$	766.2	$	680.4
Ratio of Earnings to Fixed Charges			1.99		2.27		3.45		2.94		2.78
Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements			1.75		2.03		3.14		2.60		2.35

(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 loss) 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.

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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-21

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EXHIBIT 21

SUBSIDIARIES OF CONSTELLATION ENERGY GROUP, INC.*

	Jurisdiction of Incorporation
Baltimore Gas and Electric Company	Maryland
Constellation Holdings, Inc.	Maryland
Constellation Investments, Inc.	Maryland
Constellation Power, Inc.	Maryland
Constellation Real Estate Group, Inc.	Maryland
Constellation Enterprises, Inc.	Maryland
Constellation Power Source, Inc.	Delaware
Constellation Energy Source, Inc.	Delaware
Safe Harbor Water Power Corporation	Pennsylvania
BGE Home Products & Services, Inc.	Maryland
Constellation Nuclear, LLC	Maryland
Calvert Cliffs Nuclear Power Plant, Inc.	Maryland
Constellation Nuclear Services, Inc.	Maryland
Constellation Power Source Generation, Inc.	Maryland
Constellation Power Source Holdings, Inc.	Maryland
BGE Capital Trust I	Delaware
Nine Mile Point Nuclear Station, LLC.	Delaware

*

The names of certain indirectly owned subsidiaries have been omitted because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary pursuant to Rule 1-02(w) of Regulation S-X.

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SUBSIDIARIES OF CONSTELLATION ENERGY GROUP, INC.

EX-23

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EXHIBIT 23

CONSENT OF INDEPENDENT ACCOUNTANTS

        We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 and Form S-8 (Nos. 333-81352, 333-36380, 333-59601, 33-57658, 333-56572, 333-24705, and 33-49801, and 33-59545, 333-45051, 333-46980 and 333-81292, respectively) of Constellation Energy Group, Inc. of our report dated January 21, 2002 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

PRICEWATERHOUSECOOPERS LLP

Baltimore, Maryland
March 29, 2002

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CONSENT OF INDEPENDENT ACCOUNTANTS

EX-99

March 29, 2002

VIA ELECTRONIC TRANSMISSION

Securities and Exchange Commission

Division of Corporation Finance

450 Fifth Street, N.W.

Washington, D.C. 20549

Re:File Nos. 1-12869 and 1-1910

Form 10-K for the year ended December 31, 2001

Ladies and Gentlemen:

We are transmitting to you the Form 10-K of Constellation Energy Group, Inc. and Baltimore Gas and Electric Company for the year ended December 31, 2001 for filing under the Securities Exchange Act of 1934.

Pursuant to General Instruction D(3) of Form 10-K, the financial statements in the Form 10-K reflect our adoption of Statement of Financial Accounting Standards No. 133, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities.

Kindly direct any notice concerning the Form 10-K or any questions or comments regarding our filing to me or Thomas E. Ruszin, Jr. at (410) 783-3610.

Kindly direct all EDGAR matters to Charles W. Starkey at (410) 783-3620.

Our fax number for any communication to all of these individuals is (410) 783-3629.

Very truly yours,

/s/ E. Follin Smith

E. Follin Smith

Enclosure

cc:	H. Christopher Owings, Securities and Exchange Commission
	T. E. Ruszin, Jr.
	C. W. Starkey