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

FORM 10-K

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

For the fiscal year ended DECEMBER 31, 2001

MARYLAND

(States of incorporation)

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

410-234-5000

(Registrants' telephone number, including area code)

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

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

Not Applicable

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

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE

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

TABLE OF CONTENTS

Forward Looking Statements

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

•

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

•

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

•

the conditions of the capital markets generally, which are affected by interest rates and general economic conditions, as well as Constellation Energy and BGE's ability to maintain their current credit ratings,

•

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

•

the liquidity and competitiveness of wholesale markets for energy commodities,

•

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

•

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

•

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

•

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

•

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

•

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

•

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

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

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

PART I

Item 1. Business

Overview

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

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

        Our merchant energy business includes:

•

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

•

power marketing, origination transactions, and risk management services.

1

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

        Our other nonregulated businesses include:

•

energy products and services,

•

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

•

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

•

financial investments,

•

real estate holdings and senior-living facilities, and

•

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

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

Operating Segments

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

(1)

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

Merchant Energy Business

Introduction

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

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

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

        Currently, our merchant energy business:

•

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

2

•

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

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

Generation

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

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

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

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

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

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

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

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

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

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

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

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

3

        The following table describes our generating facilities:

(A)

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

(B)

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

(C)

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

4

        The following table describes our processing facilities:

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

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

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

Fuel Sources

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

(1)

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



(2)

Switches between natural gas and oil.

Nuclear

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

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

5

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

*represents our proportionate ownership interest

        The supply of fuel for nuclear generating stations includes the:

•

purchase of uranium concentrates,

•

conversion to uranium hexafluoride,

•

enrichment of uranium hexafluoride, and

•

fabrication of nuclear fuel assemblies.

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

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

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

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

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

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

6

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

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

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

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

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

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

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

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

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

7

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

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

Power Marketing

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

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

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

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

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

•

affiliates that own generation assets,

•

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

•

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

•

regional power pools.

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

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

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

•

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

•

the hedge of electricity positions.

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

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

•

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

•

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

•

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

•

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

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

8

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

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

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

Nuclear Consulting Services

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

Competition

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

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

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

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

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

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

9

Merchant Energy Operating Statistics

        Operating statistics do not reflect the elimination of intercompany transactions.

Baltimore Gas and Electric Company

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

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

Electric Business

Electric Regulatory Matters and Competition

Restructuring Order

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

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

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

•

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

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

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

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

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

•

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

•

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

•

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

Standard Offer Service

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

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

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

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

Electric Load Management

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

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

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air conditioning control for residential and commercial customers, and

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residential water heater control.

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

Transmission and Distribution Facilities

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

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

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

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Electric Operating Statistics

(A)

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

        Operating statistics do not reflect the elimination of intercompany transactions.

Gas Business

Gas Regulatory Matters and Competition

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

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

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

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

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

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

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

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

Gas Operations

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

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Columbia Gas Transmission Corporation,

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Dominion Transmission Inc., and

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Transcontinental Gas Pipe Line Corporation.

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

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Texas Gas,

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Columbia Gulf Transmission Company, and

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ANR Pipeline Company.

        We have storage service agreements with:

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Columbia Gas Transmission Corporation,

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Dominion Transmission Inc., and

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ANR Pipeline Company.

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

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

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

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

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

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Gas Operating Statistics

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

(A)

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

(B)

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

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

        Operating statistics do not reflect the elimination of intercompany transactions.

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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. All such franchises, other than the gas franchises in Manchester, Hampstead, Perryville, Sykesville, Havre de Grace, Mt. Airy, and Montgomery

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

Other Nonregulated Businesses

Energy Products and Services

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

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

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energy consulting and power-quality services,

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

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customized financing alternatives.

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

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

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the sale and service of electric and gas appliances,

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home improvements,

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

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electric and natural gas retail marketing.

ComfortLink

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

Other

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

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

Consolidated Capital Requirements

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

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$824 million in 2002, and

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$544 million in 2003.

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

Environmental Matters

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

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air quality,

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water quality,

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chemical and waste management and disposal, and

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other environmental matters.

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

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

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

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$69 million in 2002, and

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$16 million in 2003.

Clean Air

Clean Air Act

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

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

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

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

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

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

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

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

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

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

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

Clean Water Act

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

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

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

Resource Conservation and Recovery Act

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

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

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

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

Metal Bank

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

Kane and Lombard Streets

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

Drumco Drum Dump Site

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

68^th Street Dump

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

Spring Gardens

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

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

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

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

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

Employees

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

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

Item 2. Properties

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

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

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

•

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

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

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

•

in public streets and highways pursuant to franchises, and

•

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

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

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

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

Item 3. Legal Proceedings

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

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Item 4. Submission of Matters to Vote of Security Holders

Not applicable.

Executive Officers of the Registrant

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

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

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(A)

Director and member of the Executive Committee.

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

PART II

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

Stock Trading

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

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

Dividend Policy

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

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

•

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

•

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

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

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

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

Common Stock Dividends and Price Ranges

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

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Item 6. Selected Financial Data

Constellation Energy Group, Inc. and Subsidiaries