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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, 2003

MARYLAND

(States of incorporation)

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

410-783-2800

(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 30, 2003 was approximately $5,698,266,202 based upon New York Stock Exchange composite transaction closing price.

CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE 168,103,732 SHARES OUTSTANDING ON FEBRUARY 27, 2004.

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," "anticipates," "expects," "intends," "plans," and other similar words. We also disclose non-historical information that represents management's expectations, which are based on numerous assumptions. These statements and projections are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance or achievements to be materially different from those we project. These risks, uncertainties, and factors include, but are not limited to:

•

the timing and extent of changes in commodity prices and volatilities for energy and energy related products including coal, natural gas, oil, electricity, 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 Group's (Constellation Energy) and Baltimore Gas and Electric Company's (BGE) ability to maintain their current credit ratings,

•

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

•

the liquidity and competitiveness of wholesale markets for energy commodities,

•

operational factors affecting commercial operations of our generating facilities (including nuclear facilities) and BGE's transmission and distribution facilities, including catastrophic weather related damages, unscheduled outages or repairs, unanticipated changes in fuel costs or availability, unavailability of 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 increases in 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 activities 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 Securities and Exchange Commission (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 is a North American energy company which includes a merchant energy business and BGE, its regulated electric and gas public utility in central Maryland.

        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.

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        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 (load-serving) of, and providing other energy risk management services for various customers, such as utilities, municipalities, cooperatives, retail aggregators, and commercial and industrial customers.

        Our merchant energy business includes:

•

a generation operation that owns, operates, and maintains fossil, nuclear, and hydroelectric generating facilities and interests in qualifying facilities, fuel processing facilities and power projects in the United States,

•

a marketing and risk management operation that provides energy products and services to wholesale customers,

•

an electric and gas retail operation that provides energy services to commercial and industrial customers, and

•

a generation and consulting services operation.

        BGE is a regulated electric transmission and distribution utility company and a regulated gas 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 heating, cooling, and cogeneration facilities for commercial, industrial, and municipal customers throughout North America, and

•

provide home improvements, service heating, air conditioning, plumbing, electrical, and indoor air quality systems, and provide natural gas retail marketing to residential customers in central 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 power distribution project and in a fund that holds interests in two South American energy projects.

        For a discussion of recent events that have impacted us, please refer to Item 7. Management's Discussion and Analysis—Significant Events of 2003 section. For a discussion of our 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.

        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.

        In addition, the website for Constellation Energy includes copies of our Corporate Governance Guidelines, Principles of Business Integrity, Corporate Compliance Program and Insider Trading Policy, and the charters for the Audit, Compensation and Nominating and Corporate Governance Committees of the Board of Directors. Copies of each of these documents may be printed from the website or may be obtained from Constellation Energy upon written request to the Corporate Secretary.

        The Principles of Business Integrity is a code of ethics which applies to all of our directors, officers, and employees, including the chief executive officer, chief financial officer, and chief accounting officer. We will post any amendments to, or waivers from, the Principles of Business Integrity applicable to our chief executive officer, chief financial officer, or chief accounting officer on our website.

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.

(1)

Excludes cumulative effects of changes in accounting principles as discussed in more detail in Item 8. Financial Statements and Supplementary Data.

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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 wholesale marketing and risk management operation, dispatches the energy from our generating facilities, manages the risks associated with selling the output and obtaining fuels, and structures transactions to meet customers' energy and risk management requirements. Constellation NewEnergy, our electric and gas retail operation, provides energy services to commercial and industrial customers. Generation capacity supports these marketing operations by providing a source of reliable power supply that provides a physical hedge for some of our load-serving activities.

        Our merchant energy business:

•

provided service to distribution utilities, municipalities, and commercial and industrial customers with approximately 24,000 megawatts (MW) of peak load in the aggregate during 2003,

•

provided approximately 195,000 million British Thermal Units (mmBTUs) of natural gas to commercial and industrial customers during 2003, and

•

owns approximately 12,030 MW of generation capacity.

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

•

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

•

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

•

Competitive Supply—our wholesale marketing and risk management operation that provides energy products and services to distribution utilities and other wholesale customers. We also provide electric and gas energy services to retail commercial and industrial customers.

•

Other—our 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.

Mid-Atlantic Fleet

We own 6,379 MW of fossil, nuclear and hydroelectric generation capacity in the PJM region. The output of these plants is managed by our wholesale marketing 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.

        Our merchant energy business provides standard offer service to BGE as discussed in the Baltimore Gas and Electric Company—Standard Offer Service section. Our merchant energy business meets the load-serving requirements of this contract using the output from the Mid-Atlantic Fleet and from purchases in the wholesale market. For 2003, the peak load supplied to BGE was approximately 5,270 MW.

Plants with Power Purchase Agreements

We own 3,360 MW of nuclear and natural gas/oil generation capacity with power purchase agreements for their output. Our facilities with power purchase agreements consist of:

•

the Nine Mile Point facility,

•

the High Desert Power Project, which commenced operations in early 2003,

•

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

•

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

        We purchased 100% of Nine Mile Point 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% of our share of Nine Mile Point's output to the former owners of the plant at an average price of nearly $35 per megawatt-hour (MWH) under agreements that terminate between 2009 and 2011. The agreements 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 wholesale marketing 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 with the former owners of the plant will begin and continue through 2021. Under this agreement, which applies only to Unit 2, a predetermined 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 former owners of the plant. 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 Unit 2 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 spring of 2004.

        The High Desert Power Project has a long-term power sales agreement with the California Department of Water Resources (CDWR). The contract is a "tolling" structure, under which the CDWR pays a fixed amount of $12.1 million per month and provides CDWR the right, but not the obligation, to purchase power from the project at a price linked to the variable cost of production. During the term of the contract, which runs until December 2010, the project will provide energy exclusively to the CDWR.

        We have sold portions of the output of the Oleander and University Park 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.

        On November 25, 2003, we announced an agreement with Rochester Gas & Electric (RG&E) to acquire the 495 megawatt R.E. Ginna Nuclear Power Plant (Ginna) located north of Rochester, New York. The transaction is contingent upon regulatory approvals including license extension. The acquisition includes a long-term unit contingent power purchase agreement where we will sell 90% of the plant's output and capacity to RG&E for 10 years at an average price of $44.00 per MWH. The remaining 10% of the plant's output will be managed by our wholesale marketing and risk management and will be sold into the wholesale market.

Competitive Supply

We are a leading supplier of energy products and services in North America to wholesale customers and retail commercial and industrial customers. Our competitive supply activities include 2,015 MW from our Rio Nogales, Holland Energy, Big Sandy, and Wolf Hills natural gas-fired generating facilities. These four facilities are not sold forward under long-term agreements, and their output is used to serve customer requirements.

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 to supply full energy and capacity requirements and provide other energy products and services to retail 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:

•

the New England, New York, and Mid-Atlantic regions,

•

Texas,

•

the Mid-West region,

•

the West region, 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 22,800 MW of load under contract for 2004.

        In 2003, we acquired Blackhawk Energy Services and Kaztex Energy Management and in 2002, we acquired NewEnergy and Alliance. These acquisitions expand our business in the competitive supply market by providing electricity, natural gas, transportation, and other energy related services to retail commercial and industrial customers throughout North America.

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

•

bilateral power purchase agreements with third parties,

•

our generation assets,

•

regional power pools, or

•

tolling contracts with generation companies, 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 terms that generally extend from several months to several years but can be longer.

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Portfolio Management

Our wholesale marketing 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. As part of our risk management activities we trade power and gas to enable price discovery and facilitate the hedging of our load-serving and other risk management products and services. Within our trading function we allow limited risk-taking activities for profit. These activities are actively managed through daily value at risk and liquidity position limits. We discuss value at risk in more detail in Item 7. Management's Discussion and Analysis—Market Risk.

        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),

•

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 wholesale marketing and risk management operation the ability 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 hold up to a 50% ownership interest in 25 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. In addition, we own 100% of a geothermal electric generating facility in Hawaii. Each electric generating plant sells its output to a local utility under long-term contracts.

        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, 2003 and our generation based on actual output by fuel type in 2003 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.

Nuclear

The output at Calvert Cliffs Nuclear Power Plant (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, and uranium hexafluoride)

•

conversion of uranium concentrates to uranium hexafluoride,

•

enrichment of uranium hexafluoride, and

•

fabrication of nuclear fuel assemblies.

        The nuclear fuel markets are competitive and although prices for uranium and conversion are increasing, 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. There are no facilities for the reprocessing or permanent disposal of spent nuclear fuel currently in operation in the United States, and the Nuclear Regulatory Commission (NRC) has not licensed any such facilities. The Nuclear Waste Policy Act of 1982 (NWPA) required the federal government through the Department of Energy (DOE), to develop a repository for, and disposal of, spent nuclear fuel and high-level radioactive waste.

        As required by the NWPA, we are a party to contracts with the DOE to provide for disposal of spent nuclear fuel from our nuclear generating plants. The NWPA and our contracts with the DOE require payments to the DOE of one tenth of one cent (one mill) per kilowatt hour on nuclear electricity generated and sold to pay for the cost of long-term nuclear fuel storage and disposal. We continue to pay those fees into the DOE's Nuclear Waste Fund for Calvert Cliffs and Nine Mile Point. The NWPA and our contracts with the DOE required the DOE to begin taking possession of spent nuclear fuel generated by nuclear generating units no later than January 31, 1998.

        The DOE has stated that it will not meet that obligation until 2010 at the earliest. This delay has required that we undertake additional actions related to on-site fuel storage at Calvert Cliffs and Nine Mile Point, including the installation of on-site dry fuel storage capacity at Calvert Cliffs, as described in more detail below. In January 2004, we filed a complaint against the federal government in the United States Court of Federal Claims seeking to recover damages caused by the DOE's failure to meet its contractual obligation to begin disposing of spent nuclear fuel by January 31, 1998.

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

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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 demonstrate reasonable assurance that funds will be available to decommission the sites. 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, 2003, the trust fund assets were $284.9 million.

        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, 2003, the Nine Mile Point trust fund assets were $451.2 million.

        Upon the closing of the Ginna acquisition, the seller will transfer approximately $202 million in decommissioning funds. In return, we will assume all liability for the costs to decommission the unit. The amount of the decommissioning trust fund transfer is subject to regulatory approval. We believe that this transfer will be sufficient to cover our responsibility for decommissioning Ginna to a greenfield status.

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 primary source of coal we use is produced from mines located in central and northern Appalachia. During 2003, we expanded our coal sources including restructuring our rail contracts, increasing the range of coals we can consume, adding synthetic fuel as an alternate source, and finding potential other coal supply sources including shipments from areas including Columbia, Venezuela, and South Africa.

        All of the Conemaugh and Keystone plants' annual coal requirements are purchased from regional suppliers on the open market by the plant operators. The sulfur restrictions on coal are approximately 2.3% for the Keystone plant and approximately 5.3% for the Conemaugh plant.

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        The annual coal requirements for the ACE, Jasmin, and POSO plants, which are located in California, are supplied under contracts with mining operators. The Jasmin and POSO plants are restricted to coal with sulfur content less than 4.0% and ACE is restricted to less than 2.0%.

        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, storage capacity, 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 1.5 million to 2.0 million 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 require approximately 5.0 million to 6.0 million 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 curtailed their activities, withdrawn completely from the business, or returned to a traditional utility business. However new competitors (i.e., financial investors) are entering the market. We encounter competition from companies of various sizes, having varying levels of experience, financial and human resources, and differing strategies.

        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, including various utilities, industrial companies and independent power producers (including affiliates of utilities), 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 overall 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. Some states that were considering deregulation have slowed their plans or postponed consideration of deregulation. In addition, other states are reconsidering 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.

        As the economy continues to recover and the market for commercial and industrial supply continues to grow, we have experienced increased competition in our retail commercial and industrial supply activities. The increase in retail competition may affect the margins that we will realize from our customers. 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.

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Merchant Energy Operating Statistics

        Operating statistics do not reflect the elimination of intercompany transactions.

Baltimore Gas and Electric Company

BGE is an electric transmission and distribution utility company and a gas 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 Public Service Commission (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 2003, BGE's largest electric customer provided approximately four percent of BGE's total electric revenues. In 2003, 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 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 market rate standard offer service for those commercial and industrial customers who are no longer eligible for fixed price standard offer service.

•

BGE residential base rates will not change before July 2006. While total residential base rates remain unchanged over the initial transition period (July 1, 2000 through June 30, 2006), annual standard offer service rate increases are offset by corresponding decreases 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 competitive transition charges through June 30, 2006.

•

BGE transferred, at book value, its generating assets and related liabilities to the merchant energy business. At December 31, 2003, BGE remains contingently liable for the $269.8 million outstanding balance for liabilities transferred to the merchant energy business.

Standard Offer Service

Our wholesale marketing and risk management operation provides BGE with 100% of the energy and capacity required to meet its commercial and industrial standard offer service obligations through June 30, 2004, and 100% of the energy and capacity required to meet its residential standard offer service obligations through June 30, 2006. BGE will obtain its supply for standard offer service to its commercial and industrial customers beginning July 1, 2004, and to its residential customers beginning July 1, 2006, through a competitive wholesale bidding process as discussed in the Standard Offer Service—Provider of Last Resort (POLR) section on the next page.

        Beginning July 1, 2002, the fixed price standard offer service rate ended for certain of our large commercial and industrial customers. As a result, the majority of these customers purchase their electricity

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from alternate suppliers, including subsidiaries of Constellation Energy. The remaining large commercial and industrial customers that continue to receive their electric supply from BGE are charged market-based standard offer service rates through June 30, 2004.

        Beginning July 1, 2004, all other commercial and industrial customers that receive their electric supply from BGE will be charged market-based standard offer service rates. Beginning July 1, 2006, BGE's current obligation to provide fixed price standard offer service to residential customers ends and all residential customers that receive their electric supply from BGE will be charged market-based standard offer service rates.

Standard Offer Service—Provider of Last Resort (POLR)
In April 2003, the Maryland PSC approved a settlement agreement reached by BGE and parties representing customers, industry, utilities, suppliers, the Maryland Energy Administration, the Maryland PSC's Staff, and the Office of People's Counsel which, among other things, extends BGE's obligation to supply standard offer service for a second transition period. Under the settlement agreement, BGE is obligated to provide market-based standard offer service to residential customers until June 30, 2010, and for commercial and industrial customers for one, two or four year periods beyond June 30, 2004, depending on customer load. The POLR rates charged during this time will recover BGE's wholesale power supply costs and include an administrative fee.

        In September 2003, the Maryland PSC approved a second settlement agreement. This phase deals with the bid procurement process that utilities must follow to obtain wholesale power supply to serve retail customers on standard offer service during the second transition period. The settlement contains a model request for proposals, a model wholesale power supply contract, and various requirements pertaining to, among other things, bidder qualifications and bid evaluation criteria. Bidding to supply BGE's standard offer service to commercial and industrial customers beyond June 30, 2004 began in February 2004. The same bidding procedures will be used for supplying BGE's standard offer service to residential customers for the period after June 30, 2006.

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

Electric Load Management

BGE has 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 2003 peak load from active load management was approximately 342 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 22,900 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.

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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.

Gas Business

The wholesale price of natural gas as a commodity is not subject to regulation. All BGE gas customers have the option to purchase gas from alternate suppliers, including subsidiaries of Constellation Energy. BGE continues to deliver gas to all customers within its service territory. This delivery service is regulated by the Maryland PSC.

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

        Approximately 50% of the gas delivered on BGE's distribution system is for delivery service only customers. The basis of competition for delivery service customers is primarily commodity price. BGE charges all of its delivery service customers fees to recover the costs for the transportation service it provides. These fees are the same as the delivery charges to customers that purchase gas from BGE.

        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.

        BGE purchases the natural gas it resells to customers directly from many producers and marketers. BGE has transportation and storage agreements that expire from 2005 to 2020.

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        BGE's current pipeline firm transportation entitlements to serve BGE's firm loads are 284,053 dekatherms (DTH) per day during the winter period and 259,053 DTH per day during the summer period.

        BGE's current maximum storage entitlements are 235,080 DTH per day. To supplement its gas supply at times of heavy winter demands and to be available in temporary emergencies affecting gas supply, BGE has:

•

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.

        BGE has under contract sufficient volumes of propane for the operation of the propane air facility and is capable of liquefying sufficient volumes of natural gas during the summer months for operations of its liquefied natural gas facility during winter emergencies.

        BGE historically has been able to arrange short-term contracts or exchange agreements with other gas companies in the event of short-term disruptions to gas supplies or to meet additional demand.

        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 BGE's service territory. Earnings from these activities are shared between shareholders and customers. BGE makes these sales as part of a program to balance our supply of, and cost of, natural gas.

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 them to engage in their 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 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 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

•

natural gas retail marketing to residential customers.

District Cooling Services

We provide cooling services using a central chilled water distribution system to commercial and municipal 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. While our intent is to dispose of these assets, market conditions and other events beyond our control may affect the actual sale of these assets. In addition, a future decline in the fair value of these assets could result in additional losses.

Consolidated Capital Requirements

Our total capital requirements for 2003 were $761 million. Of this amount, $472 million was used in our nonregulated businesses and $289 million was used in our utility operations. We estimate our total capital requirements to be $760 million in 2004.

       
        We continuously review and change our capital expenditure programs, so actual expenditures may vary from the estimate 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 $260 million during the five-year period 1999-2003 to comply with existing environmental standards and regulations.

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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 impose significant requirements relating to emissions of sulfur dioxide (SO₂), nitrogen oxide (NOx), particulate matter, and other pollutants 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 NOx. The EPA rule requires states to implement controls sufficient to meet their NOx budget by May 30, 2004. However, the Northeast states decided to require compliance in 2003. Coal-fired power plants are a principal target of NOx reductions under this initiative.

        Many of our generation facilities are subject to NOx 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 for our coal-fired units to meet Maryland regulations issued pursuant to the EPA's rule. The owners of the Keystone plant in Pennsylvania completed the installation of emissions reduction equipment by July 2003 to meet Pennsylvania regulations issued pursuant to the EPA's rule. Our total cost of the emissions reduction equipment at the Keystone plant was approximately $37 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.

        We may be impacted by the EPA's designation of certain areas as severe ozone nonattainment areas. These are areas where air pollution levels severely exceed national air quality standards. We own several generating facilities in severe ozone nonattainment areas in Maryland and California. The Clean Air Act requires states to assess fees against every major stationary source of NOx and volatile organic chemicals in severe ozone nonattainment areas if national air quality standards are not achieved by a specified deadline. If implemented, the fee would be assessed based on the magnitude of a source's emissions as compared to its emissions when the area failed to meet the deadline. The exact method of computing these fees has not been established and will depend in part on state implementing regulations that have not been finalized.

        The current deadline for most severe nonattainment areas is 2005, including those in which our generating facilities are located. Assessment of fees would commence in 2006 if the current effective date is maintained. However, there is significant uncertainty regarding the date when fees would be assessed in light of pending federal legislation and anticipated EPA rulemaking. Currently, we are unable to estimate the ultimate timing or financial impact of the standard in light of the uncertainty surrounding its effective date and the methodology that will be used in calculating the fees.

        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 Prevention of Significant Deterioration and non-attainment provisions of the Clean Air Act's new source review requirements. The EPA requested information relating to modifications made to our Brandon Shores, Crane, and Wagner plants in Baltimore, Maryland. The EPA also sent similar, but narrower, information requests to two of our newer Pennsylvania waste-coal burning plants. We have responded to the EPA, and as of the date of this report the EPA has taken no further action.

        Based on the level 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 if the EPA was successful in any future actions regarding our facilities.

        On October 27, 2003, the EPA's new source review rule on routine maintenance was published in the Federal Register. The new regulations would establish an equipment replacement cost threshold for determining when major new source review requirements are triggered. Plant owners may spend up to 20% of the replacement value of a generation unit on certain improvements each year without triggering requirements for new pollution controls. Parties had until December 26, 2003, the effective date of the rule, to appeal the agency's decision in court. An appeal was filed with the United States Court of Appeals. The effective date of the rule has been delayed pending review.

        The Clean Air Act required the EPA to evaluate the public health impacts of emissions of mercury, a hazardous air pollutant, from coal-fired plants. The EPA decided to control mercury emissions from coal-fired plants. On December 15, 2003, the EPA proposed two alternatives for controlling mercury emissions from generating facilities. The EPA may require the installation of mercury reduction equipment. Alternatively, the EPA may revise standards to allow for the purchase of allowances. Compliance could be required as soon as 2007, or by 2010 depending on

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which alternative is selected. We believe final regulations could be issued in 2004 and could affect all oil-fired and 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. 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.

Clean Water Act

Our facilities are subject to a variety of federal and state regulations governing existing and potential water/wastewater and storm water 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. In February 2004, the proposed rules were finalized. The final rules require the installation of additional intake screens or other protective measures, as well as extensive site-specific study and monitoring requirements. We are currently reviewing the final rules and their potential impact to us. 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 water discharge 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 clean-up requirements for threatened or actual releases of hazardous wastes 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 enacted laws similar to CERCLA. Although most wastes generated by our facilities are generally not regarded as hazardous wastes, some products used in the operations and the disposal of those materials 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 clean-up 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 (ROD) recommending clean-up for the site on December 31, 1997. On June 26, 1998, the EPA ordered BGE, the other utility PRPs, and the owner/operator to implement the requirements of the ROD. The utility PRPs have submitted the remedial design to EPA. Based on the ROD, BGE's share of the reasonably possible clean-up 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.

Kane and Lombard Streets

A 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 clean-up cost for the site to be $6.2 million.

        The EPA issued its ROD for the Kane and Lombard Drum site on September 30, 2003. The ROD specifies the clean-up plan for the site, consisting of enhanced reductive dechlorination, a soil management plan, and institutional controls. The ROD was consistent with the proposed remedy the EPA released in December 2002. We expect the EPA to approach the potentially responsible parties regarding implementation of the plan in 2004. The total clean-up costs are

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estimated to be $7.3 million. We estimate our current share of site-related costs to be 11.1% of the $7.3 million. Our share of these future costs has not been determined and it may vary from the current estimate. In December 2002, we recorded a liability in our Consolidated Balance Sheets for our share of the clean-up costs that we believe is probable.

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. In April 2003, EPA re-proposed the 68^th Street site for listing as a federal Superfund site, but decided not to include the site in its September 2003 update. BGE and other potentially responsible parties are pursuing alternatives to listing as a federal Superfund site, but at this stage, it is not possible to predict the outcome of those discussions, the clean-up cost of the site, or BGE's share of the liability. However, the costs could have a material effect on our, or BGE's, financial results.

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, located in Baltimore, Maryland, 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 BGE to implement remedial action plans for contamination at and around the Spring Gardens site. 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, 2003, 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. Based on 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.

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

Employees

Constellation Energy and its subsidiaries had, at December 31, 2003, approximately 8,650 employees. 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 June 2006. We believe that our relationship with this union is satisfactory, but there can be no assurances that this will continue to be the case.

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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 110,000 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.

        BGE's principal headquarters building is located in downtown Baltimore. In January 2004, BGE sold a portion of its headquarters building and will consolidate its operations into the remainder of the building. In addition, 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. BGE is in the process of renewing these rights-of-way with the City of Baltimore. 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 lease office space throughout North America to support our merchant energy business.

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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 Note 12 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 27, 2004, there were 48,287 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 2004, we announced an increase in our quarterly dividend from $0.26 to $0.285 per share on our common stock payable April 1, 2004 to holders of record on March 10, 2004. This is equivalent to an annual rate of $1.14 per share.

        Quarterly dividends were declared on our common stock during 2003 and 2002 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 6.20% Deferrable Interest Subordinated Debentures due 2043, 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