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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

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:

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

         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

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.

(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:

(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:

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

        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:

(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:

5

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

*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.

        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:

        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.