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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, 2002

MARYLAND

(States of incorporation)

750 E. PRATT STREET                  BALTIMORE, MARYLAND                  21202
                                               (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 ý        No o.

         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.    ý

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

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

         Aggregate market value of Constellation Energy Group, Inc. Common Stock, without par value, held by non-affiliates as of June 28, 2002 was approximately $4,791,476,554 and February 28, 2003 was approximately $4,293,890,795 based upon New York Stock Exchange composite transaction closing price.

CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE 164,764,752 SHARES OUTSTANDING ON FEBRUARY 28, 2003.

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 and volatilities for energy including coal, natural gas, oil, electricity and emission allowances,

•

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

•

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

•

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

•

the liquidity and competitiveness of wholesale markets for energy commodities,

•

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



•

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

•

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

•

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

•

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

•

changes in accounting principles or practices,

•

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

•

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

•

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

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

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

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 and Baltimore Gas and Electric Company (BGE).

        Constellation Energy maintains a website at constellation.com where copies of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments may be obtained free of charge. These reports are posted on our website the same day they are filed with the SEC. The website address for BGE is bge.com. Both website addresses are inactive textual references and the contents of these websites are not part of this Form 10-K.

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        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 is a competitive provider of energy solutions for large customers in North America. It has electric generation assets located in various regions of the United States and provides energy solutions to meet customers' needs. Our merchant energy business focuses on serving the full energy and capacity requirements of, and providing other risk management activities for various customers, such as utilities, municipalities, cooperatives, retail aggregators, and large commercial and industrial customers.

        Our merchant energy business includes:

•

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

•

origination of structured transactions (such as load-serving, tolling contracts, and power purchase agreements), and risk management services (hedging of output from generating facilities and fuel costs),

•

electric and gas retail energy services to large commercial and industrial customers, and

•

generation and consulting services.

        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.

        Our other nonregulated businesses:

•

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

•

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

•

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

        In addition, we own several investments that we do not consider to be core operations. These include financial investments, real estate projects, and interests in a Latin American distribution project and in a fund that holds interests in two South American energy projects. We decided to sell certain non-core assets and accelerated the exit strategies of other projects. We sold certain non-core assets in 2002 and closed our retail merchandise stores in December 2002.

        For a discussion of recent events that have impacted Constellation Energy, please refer to Item 7. Management's Discussion and Analysis—Significant Events section. For a discussion of Constellation Energy's strategy, please refer to Item 7. Management's Discussion and Analysis—Strategy section. For a discussion of the seasonality of our business, please refer to Item 7. Management's Discussion and Analysis—Business Environment 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 items, in Note 3 to Consolidated Financial Statements. 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 items included in operations and a cumulative effect of change in accounting principle as discussed in more detail in Item 8. Financial Statements and Supplementary Data.

2

Merchant Energy Business

Introduction

Our merchant energy business integrates electric generation assets with the marketing and risk management of energy and energy-related commodities, allowing us to manage energy price risk over geographic regions and over time. Constellation Power Source, our origination and risk management operation, dispatches the energy from our generating facilities, manages the risks associated with selling the output and obtaining the fuel, and structures transactions to meet customers' energy and risk management requirements. Generation capacity supports our origination and risk management operation by providing a source of reliable power supply that provides a physical hedge for some of our load-serving activities.

        Our merchant energy business:

•

provides service to distribution utilities, municipalities, and large commercial and industrial customers with approximately 18,700 megawatts (MW) of peak load in the aggregate,

•

owns approximately 11,300 MW of generation capacity, and

•

has under construction an 830 MW natural gas-fired combined cycle generating facility in California.

        We analyze the results of our merchant energy business as follows:

•

PJM Platform—our fossil, nuclear, and hydroelectric generating facilities and load-serving activities in the PJM Interconnection (PJM) region for which the output is primarily used to serve BGE.

•

Plants with Power Purchase Agreements—our generating facilities with long-term power purchase agreements, including our Nine Mile Point Nuclear Station (Nine Mile Point) nuclear generating facility and our new Oleander and University Park generating facilities.

•

Competitive Supply—our wholesale business that provides load-serving activities to distribution utilities (primarily in Texas and New England), other wholesale origination and risk management services, and electric and gas retail energy services to large commercial and industrial customers.

•

Other—our other gas-fired generating facilities, investments in qualifying facilities and domestic power projects, and our generation and consulting services.

        We present details about our generating properties in Item 2. Properties.

PJM Platform

We own 6,485 MW of fossil, nuclear and hydroelectric generation capacity in the PJM region. The output of these plants is managed by our origination and risk management operation and is hedged through a combination of power sales to wholesale and retail market participants.

        BGE transferred all of these facilities to our merchant energy generation subsidiaries on July 1, 2000 as a result of the implementation of electric customer choice and competition among suppliers in Maryland, except for the Handsome Lake project that commenced operations in mid-2001. The assets transferred from BGE are subject to the lien of BGE's mortgage.

        These facilities include the Calvert Cliffs Nuclear Power Plant (two units), which is our largest generating station. 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.

        Our merchant energy business provides standard offer electric service to BGE as discussed in the Baltimore Gas and Electric Company section. Our merchant energy business meets the load-serving requirements of this contract using the output from the PJM facilities and from purchases in the wholesale market. For 2002, the peak load supplied to BGE was approximately 5,425 MW.

Plants with Power Purchase Agreements

We own 2,530 MW of nuclear and natural gas generation capacity, and have under construction an 830 MW natural gas-fired facility that will commence operation in 2003, with power purchase agreements for their output. These facilities include Nine Mile Point, which is our second largest generating station. We purchased 100% of Unit 1 (609 MW) and 82% of Unit 2 (941 MW) in November 2001. 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) region.

        We sell 90 percent of our share of the Nine Mile Point plant's output back to the sellers at an average price of nearly $35 per megawatt-hour (MWH) under agreements that terminate between 2009 and 2010. 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). The remaining 10% of Nine Mile Point's output is managed by our origination and risk management operation and sold into the wholesale market.

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        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 excess amount is shared with the sellers. The revenue sharing agreement is unit contingent and is based on the operation of the unit.

        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 Nine Mile Point management committee which provides certain oversight and review functions.

        The license on Nine Mile Point's Unit 1 expires in 2009 and in 2026 on Unit 2. We have commenced a license extension initiative for both units with the objective of obtaining up to 20 years of additional operations. We expect to submit the license extension application to the NRC in the fall of 2003.

        Our other facilities with power purchase agreements consist of:

•

the Oleander project, which commenced operations in mid-2002, and

•

the University Park project, which commenced operations in mid-2001.

        We have sold portions of the output of these facilities ranging from 50% to 100% under tolling contracts for terms ending in 2005 through 2009. Under these tolling contracts, our respective counterparties will pay a fixed amount per month and have the right, but not the obligation, to purchase power from us at prices linked to the variable fuel and other costs of production.

        We are currently leasing and supervising the construction of the High Desert Power Project, an 830 MW natural-gas fired combined cycle generating facility in Victorville, California. The project is scheduled for completion in mid-2003.

        We signed a long-term power sales agreement with the State of California. The contract is a "tolling" structure, under which the California Department of Water Resources (CDWR) will pay a fixed amount of $12.1 million per month and provides the CDWR the right, but not the obligation, to purchase power from the High Desert Power Project at a price linked to the variable cost of production. During the term of the contract, which runs for seven years and nine months from the commercial operation date of the plant, the High Desert Power Project will provide energy exclusively to the CDWR. The capacity payment is proportionately reduced if the plant's availability is less than 95%. We discuss the High Desert project in more detail in Item 7. Management's Discussion and Analysis—Significant Events section.

Competitive Supply

We are a leading supplier of energy through load-serving activities in North America to wholesale customers and large commercial and industrial customers and assist them in managing their energy needs. Our competitive supply activities include the 800 MW Rio Nogales natural gas-fired generating facility that commenced operation in mid-2002 and is used to manage our Texas portfolio.

Origination of Structured Transactions

We structure transactions that serve the full energy and capacity requirements of various customers outside the PJM region such as distribution utilities, municipalities, cooperatives, and retail aggregators that do not own sufficient generating capacity or in-house supply functions to meet their own load requirements. We also structure transactions that serve the full energy and capacity requirements and other operational and administrative processes for large commercial and industrial customers.

        These activities typically occur in regional markets in which end user customers' electricity rates have been deregulated and thereby separated from the cost of generation supply. These markets include: New England, the Mid-Atlantic, Texas, the Midwest, the West, and certain areas of Canada. Contracts with these customers generally extend from one to ten years, but some can be longer. We currently have approximately 18,700 MW of load under contract for 2003.

        In 2002, we acquired NewEnergy and Alliance as discussed in Item 7. Management's Discussion and Analysis—Significant Events section. These acquisitions expand our business in the competitive supply market by providing electricity, natural gas, transportation, and other energy related services to large commercial and industrial customers throughout the United States.

        To meet our customers' load-serving requirements, our merchant energy business obtains energy from various sources, including:

•

our generation assets (including our new Rio Nogales gas-fired facility),

•

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 power purchase agreements with third parties, or

•

regional power pools.

Risk Management Activities

Our origination and risk management operation actively uses energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured 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 us to purchase or sell energy commodities in the future),

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•

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 our origination and risk management operation to manage and hedge its fixed-price purchase and sale commitments; provide fixed-price commitments to customers and suppliers; reduce exposure to the volatility of cash market prices; and hedge fuel requirements at our generation facilities.

Other

We own 1,491 MW of generating facilities and qualifying facilities and domestic power projects, which include several natural gas-fired facilities that commenced operation since 2001. The output of these facilities is managed by our origination and risk management operation and sold into the wholesale market.

        In addition, we hold up to a 50% ownership interest in 28 operating energy projects that consist of electric generation (primarily relying on alternative fuel sources), 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.

        Our merchant energy business has invested in partnerships that own 13 operating power projects of which our ownership percentage represents 137 megawatts of electricity that are sold to Pacific Gas & Electric (PGE) and to Southern California Edison (SCE) in California under power purchase agreements. The projects entered into agreements with PGE through July 2006 and SCE through April 2007 that provide for fixed-price payments averaging $53.70 per megawatt-hour plus the stated capacity payments in the original agreements.

        We also provide the following services:

•

operation and maintenance services, including testing and start-up, to owners of electric generating facilities, and

•

nuclear consulting services to the nuclear utility industry, along with plant life cycle support services, including aging management, spent fuel management, and project management and engineering.

Fuel Sources

Our power plants use diverse fuel sources. Our fuel mix based on capacity owned at December 31, 2002 and our generation based on actual output by fuel type in 2002 were as follows:

(1)

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

(2)

Switches between natural gas and oil.

         We discuss our risks associated with fuel in more detail in Item 7. Management's Discussion and Analysis—Market Risk section.

Nuclear

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

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

*represents our proportionate ownership interest

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         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 markets are competitive and we do not anticipate any problem in meeting our future 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 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 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. We will pay our portion of these fees into the DOE's Nuclear Waste Fund.

        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 disposal of spent nuclear fuel and high level nuclear waste from the nation's defense activities. In July 2002, the President signed a resolution approving the Yucca Mountain site after receiving the approval of the U.S. Senate and House of Representatives. This action allows the Department of Energy to apply to the NRC to license the project. The Department of Energy currently expects that this facility will open in 2010. However, the opening of Yucca Mountain could be delayed due to multiple lawsuits initiated by the State of Nevada and other interested parties, the NRC licensing hearings, and other issues related to the site.

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 installation that expires in 2012. We have storage capacity at Calvert Cliffs that will accommodate spent fuel from operations through 2008. In addition, we can expand our temporary storage capacity at Calvert Cliffs to meet future requirements until approximately 2025. Currently, Nine Mile Point does not have independent spent fuel storage capacity. Rather, Nine Mile Point's Unit 1 has sufficient storage capacity within the plant until the end of its current operating license in 2009. If license renewal is obtained, independent spent fuel storage capability will 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 are responsible for the costs relating to the Nine Mile Point plant.

Cost for Decommissioning
We are obligated to decommission our nuclear plants at the time these plants cease operation. Both Calvert Cliffs and Nine Mile Point are required by the NRC to prepare financially for this decommissioning. When BGE transferred all of its nuclear generating assets to our merchant energy business, it also transferred the trust fund established to pay for decommissioning Calvert Cliffs. At December 31, 2002, the trust fund was $239.7 million.

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        Under the Maryland Public Service Commission's (Maryland PSC) 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 this $520 million 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 assumed 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 our responsibility for 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). At December 31, 2002, the Nine Mile Point trust fund was $405.7 million.

Coal
We purchase the majority of our coal under supply contracts with mining operators, and we acquire the remainder in the spot or forward coal markets. We believe that we will be able to renew supply contracts as they expire or enter into contracts with other coal suppliers. 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%.

        All of our requirements reflect historical levels. The actual fuel quantities required can vary substantially from historical levels depending upon the relationship between energy prices and fuel costs, weather conditions, and operating requirements.

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 forward markets, including financial exchanges and bilateral agreements. The actual fuel quantities required can vary substantially from year to year depending upon the relationship between energy prices and fuel costs, weather conditions, and operating requirements. However, we believe that we will be able to obtain adequate quantities of gas to meet our requirements.

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 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 vary substantially from year to year depending upon the relationship between energy prices and fuel costs, weather conditions, 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.

Competition

Market developments over the past several years have changed the nature of competition in the merchant energy business. Certain companies within the merchant energy sector have either curtailed their activities or have withdrawn completely from the business. In addition, other companies are entering the market (i.e., financial investors). We encounter competition from companies of various sizes, having varying levels of experience, financial and human resources, and differing strategies.

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        We face competition in the market for energy, capacity, and ancillary services. 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 principally compete on the basis of the price, customer service, reliability, and availability of our products.

        With respect to power generation, we compete in the 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), and some of which have financial resources that are greater than ours.

        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 because 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 states considering 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. In addition, some states that were considering deregulation have slowed their plans or postponed consideration of deregulation.

        We believe there is adequate growth potential in the current deregulated market. However, in response to regional market differences and to promote competitive markets, the Federal Energy Regulatory Commission (FERC) proposed initiatives promoting the formation of Regional Transmission Organizations and a standard market design. If approved, these market changes could provide additional opportunities for our merchant energy business. Additionally, while competition has been adversely impacted by recent market events including the weakened financial condition of certain energy companies, we expect our business to become more competitive due to technological advances in power generation, e-commerce enabling new ways of conducting business, the entrance of new full service providers, and increased efficiency of energy markets.

        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.

Merchant Energy Operating Statistics

        Operating statistics do not reflect the elimination of intercompany transactions.

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Baltimore Gas and Electric Company

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. BGE is regulated by the Maryland PSC and FERC with respect to rates and other aspects of its business.

        BGE's electric service territory includes an area of approximately 2,300 square miles. There are no municipal or cooperative wholesale customers within BGE's service territory. BGE's gas service territory includes an area of approximately 800 square miles.

        BGE's electric and gas revenues come from many customers—residential, commercial, and industrial. In 2002, BGE's largest electric customer provided approximately three percent of BGE's total electric revenues. In 2002, BGE's largest gas customer provided approximately one percent of BGE's total gas revenues.

Electric Business

Electric Regulatory Matters and Competition

Deregulation

Effective July 1, 2000, electric customer choice and competition among electric suppliers was implemented in Maryland. 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 provides a fixed price standard offer service over various time periods for different classes of customers that do not select an alternative supplier until June 30, 2006.

•

While BGE does not sell electric commodity to all customers in its service territory, BGE does deliver electricity to all customers and provides meter reading, billing, emergency response, regular maintenance, and balancing services.

•

BGE provides a market rate standard offer service for those commercial and industrial customers who are no longer eligible for fixed price standard offer service until June 30, 2006.

•

BGE reduced residential base rates by approximately 6.5% on average, or about $54 million a year, from rates prior to July 1, 2000. These rates will not change before July 2006. While total residential base rates remain unchanged over this transition period (July 1, 2000 through June 30, 2006), the increase in the standard offer service rate is offset by a corresponding decrease in the competitive transition charge (CTC) that BGE receives from its customers.

•

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

•

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. At December 31, 2002, BGE remains contingently liable for the $269.8 million outstanding balance of this debt.

Standard Offer Service

Our origination and risk management operation provides BGE with 100% of the energy and capacity required to meet its standard offer service obligations through June 30, 2003. Beginning July 1, 2003, this operation 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.

        Beginning July 1, 2002, the fixed price standard offer service rate ended for large commercial and industrial customers. As a result, customers representing approximately 96% (approximately 1,200 megawatts) of load from this class purchase their electricity from an alternate supplier, including subsidiaries of Constellation Energy. The remaining large commercial and industrial customers that continue to receive their electric supply from BGE are charged market rate standard offer service.

        Beginning July 1, 2004, all other commercial and industrial customers that continue to receive their electric supply from BGE will be charged a market rate standard offer service. Currently, this class of customers represents approximately 2,200 megawatts of load. Beginning July 1, 2006, BGE's current obligation to provide fixed price standard offer service to residential customers ends.

        BGE's (and other Maryland utilities') role in providing electricity supply to customers is currently the subject of a proceeding at the Maryland PSC. Specifically, BGE entered into a proposed settlement agreement with parties representing customers, industry, utilities, suppliers, the Maryland Energy Administration, the Maryland PSC's Staff, and the Office of People's Counsel that extends BGE's obligation to supply standard offer service.

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        Under the proposed settlement agreement, BGE would be obligated to provide market-based standard offer service to residential customers until June 30, 2010, and for commercial and industrial customers for a one, two or four year period beyond June 30, 2004, depending on customer size. The rates charged during this time would be fixed during the term of the supply contract and would include an administrative fee. The proposed settlement agreement currently is before the Maryland PSC for approval.

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

Competition

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 2002 peak load from active load management was approximately 260 MW.

Transmission and Distribution Facilities

BGE maintains approximately 250 substations and 1,300 circuit miles of transmission lines throughout central Maryland. BGE also maintains nearly 22,500 circuit miles of distribution lines. The transmission facilities are connected to those of neighboring utility systems as part of the PJM Interconnection. Under the PJM Tariff and various agreements, BGE and other market participants can use regional transmission facilities for energy, capacity and ancillary services transactions including emergency assistance.

        We discuss FERC's initiatives in implementing a standard market design for wholesale electric markets in more detail in Item 7. Management's Discussion and Analysis—FERC Regulation section.

Electric Operating Statistics

(A)

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



(B)

Primarily includes transmission service integration revenues, late payment charges, miscellaneous service fees, and tower leasing revenues.

        Operating statistics do not reflect the elimination of intercompany transactions.

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Gas Business

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. BGE continues to deliver gas to all customers within its service territory. This delivery service is regulated by the Maryland PSC.

        BGE also provides these customers with meter reading, billing, emergency response, regular maintenance, and balancing services.

        Delivery service customers may choose to purchase gas from several different suppliers, including subsidiaries of Constellation Energy. The basis of competition for delivery service customers is primarily commodity price.

        Approximately 50% of the gas on our distribution system is for customers using delivery service. We charge all our delivery service customers fees to recover the costs for the transportation service we provide. These fees are the same as the delivery charges to customers that purchase gas from us.

        For customers that buy their gas from BGE, there is 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. BGE must secure fixed-price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for the November through March period.

        We purchase the natural gas we resell to customers directly from many producers and marketers. We have transportation and storage agreements that expire from 2004 to 2012.

      
        Our current pipeline firm transportation entitlements to serve our firm loads are 284,053 dekatherms (DTH) per day during the winter period and 259,053 DTH per day during the summer 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 1,092,977 DTH and a daily capacity of 311,500 DTH, and

•

a propane air facility with a mined cavern with a total storage capacity equivalent to 564,200 DTH and a 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 operations of our liquefied natural gas facility during winter emergencies.

        We historically have been able to arrange short-term contracts or exchange agreements with other gas companies in the event of short-term disruptions to gas supplies.

        BGE also participates in the interstate markets by releasing pipeline capacity or bundling pipeline capacity with gas for off-system sales. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas outside our service territory. Earnings from these activities are shared between shareholders and customers. We make these sales as part of a program to balance our supply of, and cost of, natural gas.

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Gas Operating Statistics

        Operating statistics do not reflect the elimination of intercompany transactions.

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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. Conditions of the franchises are satisfactory.

Other Nonregulated Businesses

Energy Products and Services

We offer energy products and services designed primarily to provide solutions to the energy needs of commercial and industrial customers. These energy products and services include:

•

designing, constructing, and operating single-site heating, cooling, and cogeneration facilities,

•

energy consulting and power-quality services,

•

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

•

customized financing alternatives.

Home Products and Electric and Gas Retail Marketing

We offer services to customers including:

•

home improvements,

•

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

•

electric and natural gas retail marketing.

District Cooling Services

We also provide cooling services using a central chilled water distribution system to commercial customers in the City of Baltimore.

Other

Our other nonregulated businesses include investments that we do not consider to be core operations. These include financial investments, real estate projects, and interests in a Latin American distribution project and in a fund that holds interests in two South American energy projects. In 2001, as part of our strategy to focus attention and capital resources on our core energy businesses, we accelerated our exit strategies for our remaining real estate projects and international investments.

Consolidated Capital Requirements

Our business requires a great deal of capital. Our total capital requirements for 2002 were $923 million. Of this amount, $706 million was used in our nonregulated businesses and $217 million was used in our utility operations. We estimate our total capital requirements to be $735 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, and

•

disposal of hazardous substances.

        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. We continuously monitor federal and state environmental initiatives in order to provide input as well as to maintain a proactive view of the future which is key to effective strategic planning. Additionally, as new laws or 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 $265 million during the five-year period 1998-2002 to comply with existing environmental standards and regulations, and we estimate that the future incremental capital expenditures necessary to comply with existing environmental standards and regulations will be approximately $20 million in 2003.

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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 or may require the purchase of emission allowances. Certain of these provisions are described in more detail below.

        On October 27, 1998, the Environmental Protection Agency (EPA) issued a rule requiring 22 Eastern states and the District of Columbia to reduce emissions of 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.

        Many of our generation facilities are subject to NO_X reduction requirements under the EPA rule, including those located in Maryland and Pennsylvania. At the Brandon Shores and Wagner facilities, we installed emission reduction equipment to meet Maryland regulations issued pursuant to EPA's rule. The owners of the Keystone plant in Pennsylvania are installing emissions reduction equipment by July 2003 to meet Pennsylvania regulations issued pursuant to EPA's rule. We estimate our costs for the equipment needed at this plant will be approximately $35 million. Through December 31, 2002, we have spent approximately $26 million.

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

        The EPA and several states 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, and again in 2002, 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. 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. We have responded to the EPA and as of the date of this report the EPA has taken no further action.

        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 states are seeking in these new source review enforcement actions, we believe that material additional costs and penalties could be incurred, and planned capital expenditures could be accelerated, if the EPA 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. We believe final regulations could be issued in 2004 and would affect all coal-fired boilers. The cost of compliance with the final regulations could be material.

        Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. The related Kyoto Protocol was signed by the United States but has since been rejected by the President, who instead has asked for an 18% decrease in carbon intensity on a voluntary basis. Future initiatives on this issue and the ultimate effects of the Kyoto Protocol and the President's initiatives on us are unknown at this time. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies by plant type. Fossil fuel-fired power plants are significant sources of carbon dioxide emissions, a principal greenhouse gas. Our compliance costs with any mandated federal greenhouse gas reductions in the future could be material.

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Clean Water Act

Our facilities are subject to a variety of federal and state regulations governing existing and potential water/wastewater and stormwater discharges.

        In April 2002, the EPA proposed rules under the Clean Water Act that require that cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. These rules pertain to existing utilities and non-utility power producers that currently employ a cooling water intake structure and whose flow exceeds 50 million gallons per day. We expect a final action on the proposed rules by February 2004. The proposed rule may require the installation of additional intake screens or other protective measures, as well as extensive site specific study and monitoring requirements. There is also the possibility that the proposed rules may lead to the installation of cooling towers on four of our fossil and both of our nuclear facilities. Our compliance costs associated with the final rules could be material.

        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. 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.

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 to the EPA on October 14, 1994, and the EPA issued its Record of Decision 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 Record of Decision. The utility PRPs have submitted the remedial design to EPA. Based on the Record of Decision, BGE's share of the reasonably possible cleanup costs, estimated to be approximately 15.47%, could be as much as $1.3 million higher than amounts we believe are probable and have recorded as a liability in our Consolidated Balance Sheets. There has been no significant activity with respect to this site since the EPA's Record of Decision in 1997.

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 and 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. In December 2002, the EPA released its proposed remedy for the site and estimated the total cost for the site to be $6.2 million. Until the EPA finalizes the plan, we cannot estimate BGE's share of the total site cleanup costs, but it is not expected to be material.

68th 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.

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Spring Gardens

In the past, predecessor gas companies (which were later merged into BGE) manufactured coal gas for residential and industrial use. The Spring Gardens site was once used to manufacture gas from coal and oil. 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.

        In late December 1996, BGE signed a consent order with the Maryland Department of the Environment that required it to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. BGE submitted the required remedial action plans, and they have been approved by the Maryland Department of the Environment. Based on these plans, the costs BGE considers to be probable to remedy the contamination are estimated to total $47 million. BGE recorded these costs as a liability in its Consolidated Balance Sheets and deferred these costs, net of accumulated amortization and amounts it recovered from insurance companies, as a regulatory asset. Through December 31, 2002, BGE spent approximately $39 million for remediation at this site.

        BGE also is required by accounting rules to disclose additional costs it considers to be less likely than probable, but still "reasonably possible" of being incurred at this site. Because of the results of studies at this site, it is reasonably possible that these additional costs could exceed the $47 million BGE recognized by approximately $14 million.

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

Employees

Constellation Energy and its subsidiaries had, at December 31, 2002, approximately 8,700 employees. The Central Wayne plant has a partially unionized workforce where approximately 30 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, approximately 700 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 June 2003. We believe that our relations with both unions are satisfactory, but there can be no assurances that this will continue to be the case.

        We discuss several workforce reduction programs in Item 7. Management's Discussion and Analysis—Significant Events section.

Item 2. Properties

Constellation Energy's corporate offices occupy approximately 85,000 square feet of leased office space in Baltimore, Maryland. The corporate offices for most of our merchant energy business occupy approximately 100,000 square feet of leased office space in another building in Baltimore, Maryland. We describe our electric generation properties on the next page. 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 propane air and liquefied natural gas facilities as discussed in Item 1. Business—Gas Business section.

        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 power 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.

        We also maintain office space throughout North America to support our competitive supply activities.

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        The following table describes our generating facilities:

(A)

Reflects our proportionate interest in and entitlement to capacity from Keystone and Conemaugh, which include 2 megawatts of diesel capacity for Keystone and 1 megawatt of diesel capacity for Conemaugh.

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        The following table describes our processing facilities:

Item 3. Legal Proceedings

We discuss our legal proceedings in Item 7. Management's Discussion and Analysis—Business Environment section and in Note 11 to Consolidated Financial Statements.

Item 4. Submission of Matters to Vote of Security Holders

Not applicable.

Executive Officers of the Registrant

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        Officers 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.

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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 February 28, 2003, there were 50,914 common shareholders of record.

Dividend Policy

Constellation Energy pays dividends on its common stock after its Board of Directors declares them. There are no contractual limitations on Constellation Energy paying common stock dividends.

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

        In January 2003, we announced an increase in our quarterly dividend from 24 cents to 26 cents per share on our common stock payable April 1, 2003 to holders of record on March 10, 2003. This is equivalent to an annual rate of $1.04 per share.

        Quarterly dividends were declared on our common stock during 2002 and 2001 in the amounts set forth below.

        BGE pays dividends on its common stock after its Board of Directors declares them. There are no contractual limitations 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.

Common Stock Dividends and Price Ranges

* Based on New York Stock Exchange Composite Transactions.

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Item 6. Selected Financial Data

Constellation Energy Group, Inc. and Subsidiaries