Use these links to rapidly review the document
TABLE OF CONTENTS

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

FORM 10-K

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

For the fiscal year ended DECEMBER 31, 2001

Commission
file number		   Exact name of registrant as specified in its charter   IRS Employer Identification No.

1-12869
 
CONSTELLATION ENERGY GROUP, INC.
 
52-1964611

1-1910
 
BALTIMORE GAS AND ELECTRIC COMPANY
 
52-0280210

MARYLAND

(States of incorporation)

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

410-234-5000

(Registrants' telephone number, including area code)

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

Title of each class
  
   Name of Each Exchange on Which Registered
Constellation Energy Group, Inc. Common Stock—Without Par Value )   New York Stock Exchange, Inc.
Chicago Stock Exchange, Inc.
Pacific Exchange, Inc.

7.16% Trust Originated Preferred Securities ($25 liquidation amount per preferred security) issued by BGE Capital Trust I, fully and unconditionally guaranteed, based on several obligations, by Baltimore Gas and Electric Company
)
 
New York Stock Exchange, Inc.

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

Not Applicable

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

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE

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

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

TABLE OF CONTENTS

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


Forward Looking Statements

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

        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:

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:

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


Operating Segments

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

 
   Unaffiliated Revenues
  
 
   Merchant
Energy
   Regulated
Electric
   Regulated
Gas
   Other
Nonregulated
  
2001   16 % 52 % 17 % 15 %
2000   11   55   16   18  
1999   7   59   12   22  
 
   Net Income(1)
  
 
   Merchant
Energy
   Regulated
Electric
   Regulated
Gas
   Other
Nonregulated
  
2001   70 % 20 % 9 % 1 %
2000   59   29   8   4  
1999   18   73   9   —  
 
   Total Assets
  
 
   Merchant
Energy
   Regulated
Electric
   Regulated
Gas
   Other
Nonregulated
& Corp.
Items
  
2001   57 % 27 % 8 % 8 %
2000   56   26   9   9  
1999   13   65   9   13  
(1)
Excludes special costs included in operations and nonrecurring items as discussed in more detail in Item 8. Financial Statements and Supplementary Data.


Merchant Energy Business

Introduction

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

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

        According to the McGraw-Hill publication "210 Independent Power Companies: Profiles of Industry Players and Projects," dated August 2001, we were ranked the 16th, 18th, and 83rd 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:

2

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


Generation

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

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

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

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

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

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

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

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

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

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

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

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

3

        The following table describes our generating facilities:

Plant
   Location
   Installed
Capacity (MW)
   %
Owned
   Capacity (MW)
Owned
   Primary
Fuel
 
    
   (at December 31, 2001)

    
   (at December 31, 2001)

    
Nuclear                    
  Calvert Cliffs   Calvert Co., MD   1,685   100.0   1,685  (A) Nuclear
  Nine Mile Point Unit 1   Scriba, NY   609   100.0   609   Nuclear
  Nine Mile Point Unit II   Scriba, NY   1,148   82.0   941  (B) Nuclear
       
     
   
  Total Nuclear       3,442       3,235    

Fossil
 
 
 
 
 
 
 
 
 
 
  Steam                    
  Brandon Shores   Anne Arundel Co., MD   1,300   100.0   1,300  (A) Coal
  Herbert A. Wagner   Anne Arundel Co., MD   1,006   100.0   1,006  (A) Coal/Oil/Gas
  Charles P. Crane   Baltimore Co., MD   385   100.0   385  (A) Coal
  Gould Street   Baltimore City, MD   104   100.0   104  (A) Oil/Gas
  Riverside   Baltimore Co., MD   78   100.0   78  (A) Gas
  Keystone   Armstrong and Indiana Cos., PA   1,711   21.0   359  (A),(B) Coal
  Conemaugh   Indiana Co., PA   1,711   10.6   181  (A),(B) Coal
  ACE   Trona, CA   102   30.3   31  (C) Coal
  Jasmin   Kern Co., CA   33   50.0   17  (C) Coal
  POSO   Kern Co., CA   33   50.0   17  (C) Coal
       
     
   
  Total Steam       6,463       3,478    
 
Combustion Turbine
 
 
 
 
 
 
 
 
 
 
  Perryman   Harford Co., MD   350   100.0   350  (A) Oil/Gas
  Notch Cliff   Baltimore Co., MD   128   100.0   128  (A) Gas
  Westport   Baltimore City, MD   121   100.0   121  (A) Gas
  Riverside   Baltimore Co., MD   173   100.0   173  (A) Oil/Gas
  Philadelphia Road   Baltimore City, MD   64   100.0   64  (A) Oil
  Charles P. Crane   Baltimore Co., MD   14   100.0   14  (A) Oil
  Herbert A. Wagner   Anne Arundel Co., MD   14   100.0   14  (A) Oil
  University Park   Chicago, IL   300   100.0   300   Gas
  Wolf Hills   Bristol, VA   250   100.0   250   Gas
  Handsome Lake   Rockland Twp, PA   250   100.0   250   Gas
  Big Sandy   Neal, WV   300   100.0   300   Gas
       
     
   
  Total Combustion Turbine       1,964       1,964    
       
     
   
  Total Fossil       8,427       5,442    

Hydroelectric
 
 
 
 
 
 
 
 
 
 
  Safe Harbor   Safe Harbor, PA   416   66.7   277  (A) Hydro
  Malacha   Muck Valley, CA   32   50.0   16  (C) Hydro
       
     
   
  Total Hydroelectric       448       293    

Alternative
 
 
 
 
 
 
 
 
 
 
  Mammoth Lakes G-1   Mammoth Lakes, CA   8   50.0   4   Geothermal
  Mammoth Lakes G-2   Mammoth Lakes, CA   12   50.0   6   Geothermal
  Mammoth Lakes G-3   Mammoth Lakes, CA   12   50.0   6   Geothermal
  Ormesa II   Imperial Valley, CA   17   50.0   9   Geothermal
  Puna I   Hilo, HI   30   50.0   15   Geothermal
  Soda Lake I   Fallon, NV   3   50.0   2   Geothermal
  Soda Lake II   Fallon, NV   13   50.0   7   Geothermal
  Stillwater   Fallon, NV   13   50.0   6   Geothermal
  SEGS IV   Kramer Junction, CA   30   12.0   4   Solar
  SEGS V   Kramer Junction, CA   30   4.0   1   Solar
  SEGS VI   Kramer Junction, CA   30   9.0   3   Solar
  Chinese Station   Sonora, CA   22   45.0   10   Biomass
  Fresno   Fresno, CA   24   50.0   12   Biomass
  Rocklin   Placer Co., CA   24   50.0   12   Biomass
  Central Wayne   Dearborn, MI   22   50.0   11   Municipal Solid Waste
  Colver   Colver Township, PA   110   25.0   28   Waste Coal
  Panther Creek   Nesquehoning, PA   83   50.0   42   Waste Coal
  Sunnyside   Sunnyside, UT   53   50.0   26   Waste Coal
       
     
   
  Total Alternative       536       204  (C)  
       
     
   
Total Generating Facilities       12,853       9,174    
       
     
   
(A)
The generating assets that were transferred from BGE to nonregulated subsidiaries of Constellation Energy on July 1, 2000.
(B)
These totals reflect our proportionate interest and entitlement to capacity from Nine Mile Point Unit 2 and Keystone and Conemaugh, which include 2 megawatts of diesel capacity for Keystone and 1 megawatt of diesel capacity for Conemaugh.
(C)
These totals reflect our proportionate interest in the entities that own these plants.

4

        The following table describes our processing facilities:

Plant
   Location
   Installed
Capacity (MW)
   % Owned
   Capacity (MW)
Owned
   Primary
Fuel
 
    
   (at December 31, 2001)

    
   (at December 31, 2001)

    
Gary PCI   Gary, IN   —   12.5   —   Coal Processing
PC Synfuel VA I   Appalachia, VA   —   16.7   —   Synfuel Processing
PC Synfuel WV I   Charleston, WV   —   16.7   —   Synfuel Processing
PC Synfuel WV II   Nettie, WV   —   16.7   —   Synfuel Processing
PC Synfuel WV III   Mayberry, WV   —   16.7   —   Synfuel Processing

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

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

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

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

Fuel Sources

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

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

Nuclear

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

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

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

5


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

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

*represents our proportionate ownership interest

        The supply of fuel for nuclear generating stations includes the:


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

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

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

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

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

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

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

6


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

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

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

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

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

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

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

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

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

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

7


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

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


Power Marketing

Through Constellation Power Source, Inc. (CPS) we are a leading power marketer in North America. CPS provides power marketing and risk management services to wholesale customers to assist them in managing their energy needs. Power Markets Weekly ranked CPS as the 13th 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:

        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 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:

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

8

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

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

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


Nuclear Consulting Services

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


Competition

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

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

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

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

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

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

9


Merchant Energy Operating Statistics

 
   2001

   2000

   1999

   1998

   1997
Mark-to-Market Energy Assets (In millions)   $ 2,218.2   $ 2,522.4   $ 373.4   $ 133.0   $ 9.4
Mark-to-Market Energy Liabilities (In millions)     1,799.8     1,994.5     225.1     99.0     8.6

Revenues (In millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Standard Offer Service Revenue from BGE   $ 1,269.0   $ 691.0   $ —   $ —   $ —
  Other Generation Revenue     314.1     171.9     124.3     129.4     108.1
  Mark-to-Market Energy Revenues     175.8     151.5     147.7     47.5     2.6
  Other Revenue     6.6     11.3     5.3     6.7     2.3
    Total Revenue   $ 1,765.5   $ 1,025.7   $ 277.3   $ 183.6   $ 113.0
Generated (In millions)—MWH     37.4     18.8     1.3     1.3     1.2

        Operating statistics do not reflect the elimination of intercompany transactions.


Baltimore Gas and Electric Company

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

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


Electric Business

Electric Regulatory Matters and Competition

Restructuring Order

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

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

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

10

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:

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

Transmission and Distribution Facilities

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

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

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

11


Electric Operating Statistics

 
   2001

   2000(A)

   1999

   1998

   1997
Revenues (In millions)                              
  Residential   $ 885.3   $ 922.6   $ 975.2   $ 948.6   $ 932.5
  Commercial     903.0     926.2     939.3     912.9     892.6
  Industrial     218.1     203.6     204.3     211.5     211.9
    System Sales   $ 2,006.4   $ 2,052.4   $ 2,118.8   $ 2,073.0   $ 2,037.0

Sales (In thousands)—MWH
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Residential     11,714     11,675     11,349     10,965     10,806
  Commercial     14,147     14,042     13,565     13,219     12,718
  Industrial     4,445     4,476     4,350     4,583     4,575
    System Sales     30,306     30,193     29,264     28,767     28,099

Customers (In thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Residential     1,040.5     1,033.4     1,021.4     1,009.1     1,001.0
  Commercial     110.9     108.9     107.7     106.5     105.9
  Industrial     5.0     5.0     4.7     4.6     4.5
    Total     1,156.4     1,147.3     1,133.8     1,120.2     1,111.4

        Operating statistics do not reflect the elimination of intercompany transactions.


Gas Business

Gas Regulatory Matters and Competition

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

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

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

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

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

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

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

12

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

Gas Operations

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

        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:

        We have storage service agreements with:

        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:

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

13


Gas Operating Statistics

 
   2001

   2000

   1999

   1998

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

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

        Operating statistics do not reflect the elimination of intercompany transactions.

14


Franchises

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

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


Other Nonregulated Businesses

Energy Products and Services

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


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:



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:

        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:

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

15

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

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


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 NOx (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 NOX 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 NOX (a precursor of ozone). Among other things, the EPA's rule establishes an ozone season, which runs from May through September, and a NOX emission budget for each state, including Maryland and Pennsylvania. The EPA rule requires states to implement controls sufficient to meet their NOX budget by May 30, 2004. Coal-fired power plants are a principal target of NOX 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 NOX 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

16

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

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

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

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

Clean Water Act

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

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

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

Resource Conservation and Recovery Act

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

17

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

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

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

Metal Bank

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

Kane and Lombard Streets

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

Drumco Drum Dump Site

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

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

Spring Gardens

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

18

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

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

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

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


Employees

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

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


Item 2. Properties

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

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

        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:

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.

19



Item 4. Submission of Matters to Vote of Security Holders

Not applicable.


Executive Officers of the Registrant

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

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

Name
   Age
   Present Office
   Other Offices or Positions Held
During Past Five Years
Christian H. Poindexter   63   Chairman of the Board (A) (since formation of Constellation Energy Group as the holding company on April 30, 1999; since March 1, 1998 for BGE)   Chairman of the Board, President, and Chief Executive Officer—Constellation Energy and BGE.

Mayo A. Shattuck, III
 
47
 
President and Chief Executive Officer of Constellation Energy (A) (since November 1, 2001)
 
Co-Chairman and Co-Chief Executive Officer—DB Alex Brown, LLC and Deutsche Banc Securities, Inc., Vice Chairman—Bankers Trust Corporation, and President and Chief Operating Officer and Director—Alex Brown Inc.

E. Follin Smith
 
42
 
Senior Vice President and Chief Financial Officer of Constellation Energy and Baltimore Gas and Electric Company (since June 2001)
 
Senior Vice President and Chief Financial Officer—Armstrong Holdings, Inc.; Vice President and Treasurer—Armstrong Holdings, Inc. (filed for bankruptcy under Chapter 11 on December 6, 2000); and Chief Financial Officer—General Motors—Delphi Chassis Systems.

Michael J. Wallace
 
54
 
President of Constellation Generation Group (since January 2002)
 
Managing Director and Member—Barrington Energy Partners; and Senior Vice President—Commonwealth Edison.

Thomas V. Brooks
 
39
 
President of Constellation Power Source, Inc. (since October 2001)
 
Vice President of Business Development and Strategy—Constellation Energy and Vice President—Goldman Sachs.

Frank O. Heintz
 
58
 
President and Chief Executive Officer of Baltimore Gas and Electric Company (since July 1, 2000)
 
Executive Vice President, Utility Operations—BGE; and Vice President, Gas—BGE.

Thomas F. Brady
 
52
 
Vice President Corporate Strategy and Development (since formation of Constellation Energy Group as the holding company on April 30, 1999; since January 1, 1999 for BGE)
 
Vice President, Retail Services—BGE; and Vice President, Customer Service and Distribution—BGE.

David A. Brune
 
61
 
Vice President, General Counsel, and Secretary of Constellation Energy Group (since July 2001)
 
Vice President Finance and Accounting, Chief Financial Officer and Secretary—Constellation Energy Group and BGE; and General Counsel—BGE.

 
 
 
 
 
 
 

20


Elaine W. Johnston
 
60
 
Vice President—Human Resources of Constellation Energy Group (since December 2001)
 
Managing Director Human Resources and Administration—Constellation Power Source Holdings, Inc.; Manager—Human Resources Services—Constellation Enterprises, Inc.; Manager—Staff Services—BGE; and Director of Benefits—BGE.

John R. Collins
 
44
 
Vice President and Chief Risk Officer of Constellation Energy Group (since December 2001)
 
Managing Director—Finance—Constellation Power Source Holdings, Inc.; and Treasurer and Assistant Secretary—Constellation Power Source, Inc.

Paul J. Allen
 
50
 
Vice President—Corporate Affairs of Constellation Energy Group (since May 2001)
 
Senior Vice President and Group Head—Ogilvy Public Relations.

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:

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

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

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


Common Stock Dividends and Price Ranges

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

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

21


Item 6. Selected Financial Data

Constellation Energy Group, Inc. and Subsidiaries

 
   2001
   2000
   1999
   1998
   1997
  
 
 
   (Dollar amounts in millions, except per share amounts)

  
Summary of Operations                                
  Total Revenues   $ 3,928.3   $ 3,852.5   $ 3,840.9   $ 3,386.4   $ 3,307.6  
  Total Expenses     3,570.5     3,009.9     3,081.0     2,647.9     2,584.0  
 
  Income From Operations     357.8     842.6     759.9     738.5     723.6  
  Other Income (Expense)     1.3     4.2     7.9     5.7     (52.8 )
 
  Income Before Fixed Charges and Income Taxes     359.1     846.8     767.8     744.2     670.8  
  Fixed Charges     238.8     271.4     255.0     260.6     258.7  
 
  Income Before Income Taxes     120.3     575.4     512.8     483.6     412.1  
  Income Taxes     37.9     230.1     186.4     177.7     158.0  
 
  Income Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle     82.4     345.3     326.4     305.9     254.1  
  Extraordinary Loss, Net of Income Taxes     —     —     (66.3 )   —     —  
  Cumulative Effect of Change in Accounting Principle, Net of Income Taxes     8.5     —     —     —     —  
 
  Net Income   $ 90.9   $ 345.3   $ 260.1   $ 305.9   $ 254.1  
 
 
Earnings Per Common Share and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Earnings Per Common Share — Assuming Dilution Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle   $ .52   $ 2.30   $ 2.18   $ 2.06   $ 1.72  
  Extraordinary Loss     —     —     (.44 )   —     —  
  Cumulative Effect of Change in Accounting Principle     .05     —     —     —     —  
 
  Earnings Per Common Share and                                
    Earnings Per Common Share — Assuming Dilution   $ .57   $ 2.30   $ 1.74   $ 2.06   $ 1.72  
 
  Dividends Declared Per Common Share   $ .48   $ 1.68   $ 1.68   $ 1.67   $ 1.63  
 

Summary of Financial Condition
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Total Assets   $ 14,077.6   $ 12,939.3   $ 9,745.1   $ 9,434.1   $ 8,900.0  
 
  Short-Term Borrowings   $ 975.0   $ 243.6   $ 371.5   $ —   $ 316.1  
 
  Current Portion of Long-Term Debt   $ 1,406.7   $ 906.6   $ 808.3   $ 541.7   $ 271.9  
 
  Capitalization                                
    Long-Term Debt   $ 2,712.5   $ 3,159.3   $ 2,575.4   $ 3,128.1   $ 2,988.9  
    Redeemable Preference Stock     —     —     —     —     90.0  
    Preference Stock Not Subject to Mandatory Redemption     190.0     190.0     190.0     190.0     210.0  
    Common Shareholders' Equity     3,843.6     3,174.0     3,017.5     2,995.9     2,876.4  
 
  Total Capitalization   $ 6,746.1   $ 6,523.3   $ 5,782.9   $ 6,314.0   $ 6,165.3  
 

Financial Statistics at Year End
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Ratio of Earnings to Fixed Charges     1.18     2.78     2.87     2.60     2.35  
  Book Value Per Share of Common Stock   $ 23.48   $ 21.09   $ 20.17   $ 20.08   $ 19.47  

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

22

Baltimore Gas and Electric Company and Subsidiaries

 
   2001
   2000
   1999
   1998
   1997
  
 
 
   (Dollar amounts in millions, except per share amounts)

  

Summary of Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Total Revenues   $ 2,720.7   $ 2,746.8   $ 3,092.2   $ 3,386.4   $ 3,307.6  
  Total Expenses     2,408.9     2,334.4     2,387.9     2,647.9     2,584.0  
 
  Income From Operations     311.8     412.4     704.3     738.5     723.6  
  Other Income (Expense)     0.4     7.5     8.4     5.7     (52.8 )
 
  Income Before Fixed Charges and Income Taxes     312.2     419.9     712.7     744.2     670.8  
  Fixed Charges     154.6     184.0     205.9     238.8     230.0  
 
  Income Before Income Taxes     157.6     235.9     506.8     505.4     440.8  
  Income Taxes     60.3     92.4     178.4     177.7     158.0  
 
  Income Before Extraordinary Item     97.3     143.5     328.4     327.7     282.8  
  Extraordinary Loss, Net of Income Taxes     —     —     (66.3 )   —     —  
 
  Net Income     97.3     143.5     262.1     327.7     282.8  
  Preference Stock Dividends     13.2     13.2     13.5     21.8     28.7  
 
  Earnings Applicable to Common Stock   $ 84.1   $ 130.3   $ 248.6   $ 305.9   $ 254.1  
 

Summary of Financial Condition
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Total Assets   $ 4,954.5   $ 4,654.2   $ 7,272.6   $ 9,434.1   $ 8,900.0  
 
  Short-Term Borrowings   $ —   $ 32.1   $ 129.0   $ —   $ 316.1  
 
  Current Portion of Long-Term Debt and Preference Stock   $ 666.3   $ 567.6   $ 523.9   $ 541.7   $ 271.9  
 
  Capitalization                                
    Long-Term Debt   $ 1,821.7   $ 1,864.4   $ 2,206.0   $ 3,128.1   $ 2,988.9  
    Redeemable Preference Stock     —     —     —     —     90.0  
    Preference Stock Not Subject to Mandatory Redemption     190.0     190.0     190.0     190.0     210.0  
    Common Shareholders' Equity     1,131.4     802.3     2,355.4     2,981.5     2,870.4  
 
  Total Capitalization   $ 3,143.1   $ 2,856.7   $ 4,751.4   $ 6,299.6   $ 6,159.3  
 

Financial Statistics at Year End
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Ratio of Earnings to Fixed Charges     1.99     2.27     3.45     2.94     2.78  
  Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends     1.75     2.03     3.14     2.60     2.35  

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

23


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


Introduction

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

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

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

        Our merchant energy business includes:

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

        Our other nonregulated businesses include:

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

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

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


Critical Accounting Policies

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

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

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

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


Revenue Recognition/Mark-to-Market Method of Accounting

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

24

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

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

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

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

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


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

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

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


Events of 2001

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

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

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


Contract Termination Related Costs

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


Sale of Guatemalan Operations

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

25

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

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


Workforce Reduction Programs

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

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

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

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


Impairment Losses and Other Costs

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

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

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

        We discuss these special costs further in Note 2.


Acquisition of Nine Mile Point

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

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

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


Enron

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


Bethlehem Steel

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

26

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


New President and Chief Executive Officer

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


Certain Relationships

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


Events of 2002

Dividend Increase

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


Investment in Orion

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


Investment in Corporate Office Properties Trust (COPT)

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


Strategy

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

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

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

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

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

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

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

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

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

27

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

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


Business Environment

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

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


Electric Competition

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

Maryland

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

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

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

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

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

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

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

Other States

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

28

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

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

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

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

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

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

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

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

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


Gas Competition

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


Market Risks

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

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


Regulation by the Maryland PSC

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

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

29

Base Rate

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

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

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

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

Fuel Rate

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

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

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

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


FERC Regulation—Regional Transmission Organizations

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

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

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

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

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


Weather

Merchant Energy Business

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

BGE

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

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

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

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

30

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

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

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


Other Factors

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

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


Environmental and Legal Matters

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


Accounting Standards Adopted and Issued

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


Results of Operations

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


Overview

Net Income

 
   2001
   2000
   1999
  
 
 
   (In millions)

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

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


2001

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

31

        These decreases were partially offset by the following:

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

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


2000

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

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

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

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

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

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

32


Merchant Energy Business

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

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

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

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

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

Net Income

 
   2001
   2000
   1999
  
 
 
   (In millions)

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

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

Revenues

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

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

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

Revenues from BGE Standard Offer Service

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

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

33

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

Other Generation Revenues

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

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

        These increases were partially offset by the following:

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

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

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

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

California Power Purchase Agreements

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

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

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

        We also describe these projects in Note 11.

Mark-to-Market Energy Revenues

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

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

        Mark-to-market energy revenues were as follows:

 
   2001
   2000
   1999
  
 
 
   (In millions)

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

34

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

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

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

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

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

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

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

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

At December 31,

   2001
   2000
 
   (In millions)
Current Assets   $ 398.4   $ 453.1
Noncurrent Assets     1,819.8     2,069.3
Total Assets     2,218.2     2,522.4

Current Liabilities
 
 
323.3
 
 
358.2
Noncurrent Liabilities     1,476.5     1,636.3
Total Liabilities     1,799.8     1,994.5
Net mark-to-market energy asset   $ 418.4   $ 527.9

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

Change in Net Mark-to-Market Energy Asset

  
 
(In millions)

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

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

35


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

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

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

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

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

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

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

        The electricity, fuel, and other energy contracts held by Constellation Power Source have varying terms to maturity, ranging from contracts for delivery the next hour to contracts with terms of ten years or more. Because an active, liquid electricity futures market comparable to that for other

36

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

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

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

Operating Expenses

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

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

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

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

Extended Nuclear Outages

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

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

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

37

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

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

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

Depreciation and Amortization Expense

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

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

Taxes Other than Income Taxes

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


Regulated Electric Business

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

Net Income

 
   2001
   2000
   1999
  
 
 
   (In millions)

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

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

Electric Revenues

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

 
   2001
   2000
  
 
 
   (In millions)

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

Electric System Sales Volumes

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

38

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

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

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

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

Rates

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

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

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

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

Fuel Rate Surcharge

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

Interchange and Other Sales

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

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

Electric Fuel and Purchased Energy Expenses

 
   2001
   2000
   1999
  
 
 
   (In millions)

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

Actual Costs

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

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

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

Electric Fuel Rate Clause

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

39

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

Electric Operations and Maintenance Expenses

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

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

Workforce Reduction Costs

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

Electric Depreciation and Amortization Expense

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

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

Electric Taxes Other Than Income Taxes

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

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

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


Regulated Gas Business

Net Income

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

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

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

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

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

40

Gas Revenues

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

 
   2001
   2000
  
 
 
   (In millions)

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

Gas System Sales Volumes

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

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

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

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

Base Rates

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

Weather Normalization

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

Gas Cost Adjustments

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

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

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

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

Off-System Sales

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

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

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

Gas Purchased For Resale Expenses

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

41

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

Other Gas Operating Expenses

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

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


Other Nonregulated Businesses

Net Income

 
   2001
   2000
   1999
  

 
 
   (In millions)

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

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

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

        We discuss these special costs further in Note 2.

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

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

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

42

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

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


Consolidated Nonoperating Income and Expenses

Fixed Charges

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

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

Income Taxes

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


Financial Condition

Cash Flows

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

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

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


Security Ratings

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

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

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

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

 
   Standard
& Poors
Rating
Group
  Moody's
Investors
Service
  Fitch-
Ratings

Constellation Energy            
  Commercial Paper   A-2   P-2   F-2
  Senior Unsecured Debt   BBB+   Baa1   A-
BGE            
  Commercial Paper   A-2   P-1   F-1
  Mortgage Bonds   A   A1   A+
  Senior Unsecured Debt   BBB+   A2   A
  Trust Originated Preferred Securities and Preference Stock   BBB   Baa1   A-


Available Sources of Funding

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

43

Constellation Energy

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

BGE

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

Other Nonregulated Businesses

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

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


Capital Resources

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

        We will continue to have cash requirements for:

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

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

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

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

 
   1999
   2000
   2001
   2002
   2003
 
   (In millions)
Nonregulated Capital Requirements:      
  Merchant Energy                              
    Construction program   $ 86   $ 537   $ 697   $ 152   $ —
    Steam generators     —     21     53     91     65
    Nine Mile Point acquisition     —     —     771     —     —
    Environmental controls     —     45     89     69     16
    Continuing requirements (including nuclear fuel)     77     96 *   205     243     199
  Total Merchant Energy capital requirements     163     699     1,815     555     280
  Other Nonregulated capital requirements     115     131     35     39     34
  Total Nonregulated capital requirements     278     830     1,850     594     314

Utility Capital Requirements:
 
 
 
  Regulated electric                              
    Generation (including nuclear fuel)     117     73     —     —     —
    Steam generators     34     13     —     —     —
    Environmental controls     31     17     —     —     —
    Transmission and distribution     185     187     180     174     174
  Total regulated electric     367     290     180     174     174
  Regulated gas     69     60     59     56     56
  Total Utility capital requirements     436     350     239     230     230
Total capital requirements   $ 714   $ 1,180   $ 2,089   $ 824   $ 544

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

44


Capital Requirements

Merchant Energy Business

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

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

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

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

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

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

Regulated Electric and Gas

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


Funding for Capital Requirements

Merchant Energy Business

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

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

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

BGE

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

Other Nonregulated Businesses

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

45

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


Committed Amounts

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

 
   Payments/Expiration
 
   Less than
one year
   One-
three years
   Four-
five years
   Over
five years
   Total
 
   (In millions)
Contractual Obligations                              
  Short-term borrowings   $ 975.0   $ —   $ —   $ —   $ 975.0
  Nonregulated long-term debt     720.4     169.8     456.8     357.1     1,704.1
  BGE long-term debt     519.8     441.0     511.8     947.7     2,420.3
  BGE preference stock     —     130.0     60.0     —     190.0
  Fuel and transportation     353.1     330.0     97.9     17.7     798.7
  Purchased capacity and energy     16.4     31.5     30.1     98.5     176.5
  Operating leases     9.1     63.3     51.2     145.8     269.4
  Capital and loan commitments*     81.5     0.8     —     —     82.3
Total contractual obligations     2,675.3     1,166.4     1,207.8     1,566.8     6,616.3
Contingent Obligations                              
  Letters of credit     245.6     0.2     —     —     245.8
  Guarantees, net**     427.8     38.4     666.1     236.1     1,368.4
Total contingent obligations     673.4     38.6     666.1     236.1     1,614.2
Total obligations   $ 3,348.7   $ 1,205.0   $ 1,873.9   $ 1,802.9   $ 8,230.5
*
Amounts are included for applicable periods in our capital requirements table.
**
Guarantees in the above table are shown net of liabilities recorded at December 31, 2001 in our Consolidated Balance Sheets.

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

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

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


Liquidity Provisions

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

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

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

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

46


Market Risk

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


Interest Rate Risk

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

Principal Payments and Interest Rate Detail by Contractual Maturity Date

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

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


Commodity Price Risk

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

Merchant Energy Business

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

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

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

47

Power Marketing

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

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

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

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

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

Generation

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

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

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

48

hedge the variability in future cash flows from forecasted sales of electricity and purchases of fuel. The objectives for entering into such hedges include:

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

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

Regulated Electric Business

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

Regulated Gas Business

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


Credit Risk

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

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

        Due to the possibility of extreme volatility in the prices of energy commodities and derivatives, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, fail to deliver the electricity the power marketing operation had contracted for), we could sustain a loss that could have a material impact on our financial results.

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


Equity Price Risk

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

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


Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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

49


Item 8. Financial Statements and Supplementary Data

REPORT OF MANAGEMENT

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

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

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




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

REPORT OF INDEPENDENT ACCOUNTANTS

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

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

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

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

SIGNATURE

PricewaterhouseCoopers LLP
Baltimore, Maryland
January 21, 2002

50

CONSOLIDATED STATEMENTS OF INCOME

Constellation Energy Group, Inc. and Subsidiaries

Year Ended December 31,

   2001
   2000
   1999
  
 
 
   (In millions, except per share amounts)

  
Revenues                    
  Nonregulated revenues   $ 1,214.4   $ 1,114.0   $ 1,105.6  
  Regulated electric revenues     2,039.6     2,134.7     2,258.8  
  Regulated gas revenues     674.3     603.8     476.5  
 
  Total revenues     3,928.3     3,852.5     3,840.9  
Expenses                    
  Operating expenses     2,392.2     2,311.4     2,339.6  
  Workforce reduction costs     105.7     7.0     —  
  Contract termination related costs     224.8     —     —  
  Impairment losses and other costs     202.1     —     64.3  
  Depreciation and amortization     419.1     470.0     449.8  
  Taxes other than income taxes     226.6     221.5     227.3  
 
  Total expenses     3,570.5     3,009.9     3,081.0  
 
Income from Operations     357.8     842.6     759.9  
Other Income     1.3     4.2     7.9  
 
Income Before Fixed Charges and Income Taxes     359.1     846.8     767.8  
Fixed Charges                    
  Interest expense     283.2     282.4     248.0  
  Interest capitalized and allowance for borrowed funds used during construction     (57.6 )   (24.2 )   (6.5 )
  BGE preference stock dividends     13.2     13.2     13.5  
 
  Total fixed charges     238.8     271.4     255.0  
 
Income Before Income Taxes     120.3     575.4     512.8  
Income Taxes     37.9     230.1     186.4  
 
Income Before Extraordinary Item and Cumulative Effect of
Change in Accounting Principle		     82.4     345.3     326.4  
Extraordinary Loss, Net of Income Taxes of $30.4 (see Note 5)     —     —     (66.3 )
Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes of $5.6 (see Note 1)		     8.5     —     —  
 
Net Income   $ 90.9   $ 345.3   $ 260.1  
 

Earnings Applicable to Common Stock
 
$
90.9
 
$
345.3
 
$
260.1
 
 

Average Shares of Common Stock Outstanding
 
 
160.7
 
 
150.0
 
 
149.6
 
Earnings Per Common Share and Earnings Per Common Share—Assuming Dilution Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle   $ .52   $ 2.30   $ 2.18  
Extraordinary Loss     —     —     (.44 )
Cumulative Effect of Change in Accounting Principle     .05     —     —  
 
Earnings Per Common Share and
Earnings Per Common Share—Assuming Dilution		   $ .57   $ 2.30   $ 1.74  
 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Constellation Energy Group, Inc. and Subsidiaries

Year Ended December 31,

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

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

51

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

At December 31,

   2001
   2000
  
 
 
   (In millions)

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

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

52

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

At December 31,

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

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

53


CONSOLIDATED STATEMENTS OF CASH FLOWS

Constellation Energy Group, Inc. and Subsidiaries

Year Ended December 31,

   2001
   2000
   1999
  
 
 
   (In millions)

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

Other Cash Flow Information:
 
 
 
 
 
 
 
 
 
 
  Cash paid during the year for:                    
    Interest (net of amounts capitalized)   $ 238.3   $ 268.2   $ 245.3  
    Income taxes   $ 101.5   $ 184.7   $ 165.6  

Non-Cash Transaction:
 
 
 
 
 
 
 
 
 
 
  In connection with our purchase of Nine Mile Point, the fair value of the net assets purchased was $770.8 million. We paid $382.7 million in cash, including settlement costs, and incurred a sellers' note of $388.1 million as discussed further in Note 14.  

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

54


CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY

Constellation Energy Group, Inc. and Subsidiaries

 
    
    
    
   Accumulated Other Comprehensive Income
    
  
Years Ended December 31, 2001, 2000, and 1999

   Common Stock
  Retained Earnings
   Total Amount
  
  Shares
   Amount
  
 
 
   (Dollar amounts in millions, number of shares in thousands)

  

Balance at December 31, 1998
 
149,246
 
$
1,485.1
 
$
1,490.3
 
$
20.5
 
$
2,995.9
 

Net income
 
 
 
 
 
 
 
260.1
 
 
 
 
 
260.1
 
Common stock dividend declared ($1.68 per share)               (251.3 )         (251.3 )
Common stock issued   310     9.6                 9.6  
Other         (0.7 )               (0.7 )
Net unrealized gain on securities, net of taxes of $3.2                     3.9     3.9  
 
Balance at December 31, 1999   149,556     1,494.0     1,499.1     24.4     3,017.5  

Net income
 
 
 
 
 
 
 
345.3
 
 
 
 
 
345.3
 
Common stock dividend declared ($1.68 per share)               (251.8 )         (251.8 )
Common stock issued   976     35.9                 35.9  
Other         8.8     (0.3 )         8.5  
Net unrealized gain on securities, net of taxes of $9.5                     18.6     18.6  
 
Balance at December 31, 2000   150,532     1,538.7     1,592.3     43.0     3,174.0  

Net income
 
 
 
 
 
 
 
90.9
 
 
 
 
 
90.9
 
Common stock dividend declared ($.48 per share)               (77.1 )         (77.1 )
Common stock issued   13,176     504.4                 504.4  
Other         (0.9 )   5.4           4.5  
Cumulative effect of change in accounting principle,
net of taxes of $22.6		                     (35.5 )   (35.5 )
Net unrealized gain on securities, net of taxes of $71.8                     124.5     124.5  
Net unrealized gain on hedging instruments, net of
taxes of $65.6		                     102.6     102.6  
Minimum pension liability, net of taxes of $29.3                     (44.7 )   (44.7 )
 
Balance at December 31, 2001   163,708   $ 2,042.2   $ 1,611.5   $ 189.9   $ 3,843.6  
 

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

55

CONSOLIDATED STATEMENTS OF CAPITALIZATION

Constellation Energy Group, Inc. and Subsidiaries

At December 31,

   2001
   2000
  
 
 
   (In millions)

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

See Notes to Consolidated Financial Statements.

continued on next page

56

CONSOLIDATED STATEMENTS OF CAPITALIZATION

Constellation Energy Group, Inc. and Subsidiaries

At December 31,

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

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

57


CONSOLIDATED STATEMENTS OF INCOME TAXES

Constellation Energy Group, Inc. and Subsidiaries

Year Ended December 31,

   2001
   2000
   1999
    
 
   (Dollar amounts in millions)

    
Income Taxes                      
  Current                      
    Federal   $ 45.5   $ 148.2   $ 176.3    
    State     27.0     48.2     5.7    
  Current taxes charged to expense     72.5     196.4     182.0    
  Deferred                      
    Federal     (22.4 )   53.9     5.8    
    State     (4.1 )   (11.8 )   7.2    
  Deferred taxes charged to expense     (26.5 )   42.1     13.0    
  Investment tax credit adjustments     (8.1 )   (8.4 )   (8.6 )  
  Income taxes per Consolidated Statements of Income   $ 37.9   $ 230.1   $ 186.4    

Reconciliation of Income Taxes Computed at Statutory
Federal Rate to Total Income Taxes
 
 
 
 
 
 
 
 
 
 
 
  Income before income taxes (excluding BGE preference stock dividends)   $ 133.5   $ 588.6   $ 526.3    
    Statutory federal income tax rate     35 %   35 %   35 %  
    Income taxes computed at statutory federal rate     46.7     206.0     184.2    
    Increases (decreases) in income taxes due to                      
      Depreciation differences not normalized on regulated activities     5.6     12.6     15.3    
      Allowance for equity funds used during construction     (1.1 )   (0.9 )   (2.2 )  
      Amortization of deferred investment tax credits     (8.1 )   (8.4 )   (8.6 )  
      Tax credits flowed through to income     (13.4 )   (6.5 )   (3.2 )  
      Amortization of deferred tax rate differential on regulated activities     (2.1 )   (2.9 )   (3.0 )  
      State income taxes, net of federal income tax benefit     13.5     31.7     8.2    
      Other     (3.2 )   (1.5 )   (4.3 )  
    Total income taxes   $ 37.9   $ 230.1   $ 186.4    
    Effective income tax rate     28.4 %   39.1 %   35.4 %  

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

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

58

CONSOLIDATED STATEMENTS OF INCOME

Baltimore Gas and Electric Company and Subsidiaries

Year Ended December 31,

   2001
   2000
   1999
  
 
 
   (In millions)

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

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Baltimore Gas and Electric Company and Subsidiaries

Year Ended December 31,

   2001
   2000
   1999
  
 
 
   (In millions)

  
Net Income   $ 97.3   $ 143.5   $ 262.1  
Other comprehensive loss, net of taxes     —     —     (3.4 )
 
Comprehensive Income   $ 97.3   $ 143.5   $ 258.7  
 

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

59

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

At December 31,

   2001
   2000
  
 
 
   (In millions)

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

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

60

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

At December 31,

   2001
   2000
  
 
 
   (In millions)

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

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

61


CONSOLIDATED STATEMENTS OF CASH FLOWS

Baltimore Gas and Electric Company and Subsidiaries

Year Ended December 31,

   2001
   2000
   1999
  
 
 
   (In millions)

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

Other Cash Flow Information
 
 
 
 
 
 
 
 
 
 
  Cash paid during the year for:                    
    Interest (net of amounts capitalized)   $ 162.0   $ 184.7   $ 200.2  
    Income taxes   $ 102.8   $ 127.6   $ 178.8  

Noncash Investing and Financing Activities:
 
  On July 1, 2000, BGE transferred $1,578.4 million of generation assets, net of associated liabilities, to nonregulated affiliates of Constellation Energy pursuant to the Maryland PSC's Restructuring Order.  

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

62


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1 Significant Accounting Policies

Nature of Our Business

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

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


Consolidation Policy

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

Consolidation

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

The Equity Method

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

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

The Cost Method

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


Regulation of Utility Business

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

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

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


Revenues

Nonregulated Businesses

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

63

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

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

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

Regulated Utility

We record utility revenues when we provide service to customers.


Fuel and Purchased Energy Costs

We incur costs for:

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

Fuel Used to Generate Electricity and Purchases of Electricity From Others

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

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

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

Natural Gas

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


Risk Management

We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price and transportation costs of electricity, natural gas, and other commodities as discussed further in Note 12. We use interest rate swaps to manage our interest rate exposures associated with new debt issuances. These swaps are designated as cash-flow hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as discussed later in this note, with our gains recorded in "Other current assets" in our Consolidated Balance Sheets and "Accumulated other comprehensive income," in our Consolidated Statements of

64

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

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

Merchant Energy Business

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

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

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

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

Regulated Electric Business

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

Regulated Gas Business

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

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

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

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

Credit Risk

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

        Due to the possibility of extreme volatility in the prices of energy commodities and derivatives, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those

65

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

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


Taxes

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

Income Tax Expense

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

Investment Tax Credits

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

Deferred Income Tax Assets and Liabilities

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

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

State and Local Taxes

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

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


Cash and Cash Equivalents

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

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


Inventory

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


Real Estate Projects and Investments

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

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


Financial Investments and Trading Securities

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

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

66

Trading Securities

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

Available-for-Sale Securities

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

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

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


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

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

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


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

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

        Our original costs include:

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

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

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

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

Depreciation Expense

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

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

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

Amortization Expense

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

67

Nuclear Fuel

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

Nuclear Decommissioning

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

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

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

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

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

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


Capitalized Interest and Allowance for Funds Used During Construction

Capitalized Interest

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

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

Allowance for Funds Used During Construction (AFC)

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

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


Long-Term Debt

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

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


Use of Accounting Estimates

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

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

68


Reclassifications

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


Accounting Standards Adopted

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

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

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

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

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

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


Recently Issued Accounting Standards

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

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

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

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

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

69

2 Contract Termination, Workforce Reduction, and Other Special Costs

2001 Events

    
    
 
   Pre-Tax
   After-Tax
 
   (In millions)
Workforce reduction costs:            
  Voluntary termination benefits—VSERP   $ 70.1   $ 42.5
  Settlement and curtailment charges     16.3     9.9
  Involuntary severance accrual     19.3     11.7
  Total workforce reduction costs     105.7     64.1

Contract termination related costs
 
 
224.8
 
 
139.6

Impairment losses and other costs:
 
 
 
 
 
 
  Loss on sale of Guatemalan operation     43.3     28.1
  Impairments of real estate, senior-living and international investments     107.3     69.7
  Cancellation of domestic power projects     46.9     30.5
  Reduction of financial investment     4.6     2.8
  Total impairment losses and other costs     202.1     131.1

Total special costs
 
$
532.6
 
$
334.8


Workforce Reduction Costs

Voluntary Special Early Retirement Programs—VSERP

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

        Since employees electing to participate in the age 55 or older VSERP had to make their elections by the end of 2001, the cost of that program was reflected in 2001. The $70.1 million in the above table reflects the portion of the total cost of that program charged to expense for the 507 employees that elected to participate. BGE recorded $37.9 million of this amount. BGE also recorded $13.7 million on its balance sheet as a regulatory asset related to its gas business as discussed in Note 6.

Settlement and Curtailment Charges

In connection with the age 55 or older VSERP, a significant number of the participants in our nonqualified pension plans are retiring. As a result, we recognized a settlement loss of approximately $10.5 million and a curtailment loss of approximately $5.8 million for those plans in accordance with SFAS No. 88, Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits. BGE recorded $6.6 million of this amount. Additional details on the VSERP and their impact on our pension and postretirement benefit plans are discussed in Note 7.

Involuntary Severance Accrual

The voluntary programs were designed, offered, and timed to minimize the number of employees who will be involuntarily severed under our overall workforce reduction plan. Our workforce reduction plan identified 435 jobs to be eliminated over and above position reductions expected to be satisfied through the age 55 and over VSERP and was specific as to company, organizational unit, and position. However, the number of employees that will elect to voluntarily retire under the age 50 to 54 VSERP and how many will thereafter be involuntarily severed is unknown until after the election period of the VSERP ends in February 2002.

        In accordance with EITF 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring), the Company recognized a liability of $25.1 million at December 31, 2001 for the targeted number of involuntary terminations that will result if no employees elect the age 50 to 54 VSERP. The $19.3 million in the table above represents involuntary severance charged to expense in 2001 in connection with our workforce reduction programs. BGE recorded $12.5 million of this amount. BGE also recorded $5.8 million on its balance sheet as a regulatory asset related to its gas business as discussed in Note 6. We will record any additional cost in excess of the 2001 involuntary severance accrual for those eligible participants that elect the 50 to 54 VSERP in 2002.


Contract Termination Related Costs

On October 26, 2001, we announced the decision to remain a single company and canceled prior plans to separate our merchant energy business from our remaining businesses.

        We also announced the termination of our power business services agreement with Goldman Sachs. We paid Goldman Sachs a total of $355 million, representing $196.7 million to terminate the power business services agreement with our power marketing operation and $159 million previously recognized as a payable for services rendered under the agreement. Goldman Sachs also will not make an equity investment in our merchant energy business as previously announced.

        In addition, we terminated a software agreement we had whereby Goldman Sachs would provide maintenance, support, and minor upgrades to our risk management and trading system. We recognized $17.6 million in expense in the fourth quarter of 2001 representing the unamortized prepaid costs related to this agreement. Finally, we incurred approximately $10.5 million in employee-related expenses and advisory costs from investment bankers and legal counsel. In total, we recognized expenses of approximately $224.8 million in the fourth quarter of 2001

70

relating to the termination of our relationship with Goldman Sachs and our decision not to separate.


Impairment Losses and Other Costs

Sale of Guatemalan Operation

On November 8, 2001, we sold our Guatemalan power plant operations to an affiliate of Duke Energy International, LLC, the international business unit of Duke Energy. Through this sale, Duke Energy acquired Grupo Generador de Guatemala y Cia., S.C.A., which owns two generating plants at Esquintla and Lake Amatitlan in Guatemala. The combined capacity of the plants is 167 megawatts. We decided to sell our Guatemalan operations to focus our efforts on our core energy businesses. As a result of this transaction, we are no longer committed to making significant future capital investments in a non-core operation. We recorded a $43.3 million loss on this sale.

Impairments of Real Estate, Senior-Living, and Other International Investments

In the fourth quarter of 2001, our other nonregulated businesses recorded $107.3 million in impairments of certain real estate projects, senior-living facilities, and international assets to reflect the fair value of these investments. These investments represent non-core assets with a book value of approximately $140.6 million after these impairments. As part of our focus on capital and cash requirements and on our core energy businesses, the following occurred:

        The impairments of our real estate, senior-living facilities, and Panama investments were recorded in accordance with the provisions of SFAS No. 121. These impairments resulted from our change from an intent to hold to an intent to sell certain of these non-core assets in 2002, and our decision to limit future costs and risks by accelerating the exit strategies for certain assets that cannot be sold by the end of 2002. Previously, our strategy for these investments was to hold them until we could obtain reasonable value. Under that strategy, the expected cash flows were greater than our investment and no impairment was recognized.

Impairment of Domestic Power Projects

In the fourth quarter of 2001, our merchant energy business recorded impairments of $46.9 million primarily due to $40.8 million in impairments under SFAS No. 121 associated with the termination of our planned development projects in Texas, California, Florida, and Massachusetts that are not currently under construction. The impairments include amounts paid for the purchase of four turbines related to these development projects. We decided to terminate our development projects due to the expected excess generation capacity in most domestic markets and the significant decline in the forward market prices of electricity. In accordance with the provisions of APB No. 18, we recognized $6.1 million for an other than temporary decline in the value of our investment in a waste burning power plant in Michigan where operating cash flows are not sufficient to pay existing debt service and we are not likely to recover our equity interest in this investment.

Reduction of Financial Investment

Our financial investments business recorded a $4.6 million reduction of its investment in a leased aircraft due to the other than temporary decline in the estimated residual value of used airplanes as a result of the September 11, 2001 terrorist attacks and the general downturn in the aviation industry. This investment is accounted for as a leveraged lease under SFAS No. 13, Accounting for Leases.


2000 Events

In 2000, BGE offered a targeted VSERP to employees ages 55 or older with 10 or more years of service in targeted positions that elected to retire on June 1, 2000 to reduce our operating costs to become more competitive. BGE recorded approximately $10.0 million pre-tax for employees that elected to participate in the program. Of this amount, BGE recorded approximately $3.0 million on its balance sheet as a regulatory asset of its gas business. BGE is amortizing this regulatory asset over a 5-year period as provided by the June 2000 Maryland PSC gas base rate order as discussed in Note 6. The remaining $7.0 million, or $4.2 million after-tax, related to BGE's electric business and was charged to expense.


1999 Events

Our generation operation recorded a $21.4 million pre-tax, or $14.2 million after-tax, impairment of two geothermal power projects. These impairments occurred because the expected future cash flows from the projects are less than the investment in the projects. For the first project, this resulted from the

71

inability to restructure certain project agreements. For the second project, we experienced a declining water temperature of the geothermal resource used by one of the plants for production.

        Our Latin American operation recorded a $7.1 million pre-tax, or $4.5 million after-tax, impairment to reflect the fair value of our investment in a generating company in Bolivia as a result of our international exit strategy at that time to focus on our core businesses.

        Our financial investments exchanged its shares of common stock in Capital Re, an insurance company, for common stock of ACE Limited (ACE) as part of a business combination whereby ACE acquired all of the outstanding capital stock of Capital Re. As a result, our financial investments operation wrote-down its $94.2 million investment in Capital Re stock by $26.2 million pre-tax, or $16.0 million after-tax, to reflect the closing price of the business combination.

        Our real estate and senior-living facilities operations entered into an agreement to sell all but one of its senior-living facilities to Sunrise Assisted Living, Inc. Under the terms of the agreement, Sunrise was to acquire twelve of our existing senior-living facilities, three facilities under construction, and several sites under development for $72.2 million in cash and $16.0 million in debt assumption. We could not reach an agreement on financing issues that subsequently arose, and the agreement was terminated in November 1999. However, our real estate and senior-living operations recorded a $9.6 million pre-tax, or $5.8 million after-tax, impairment related to the proposed sale of these facilities.

3 Information by Operating Segment

Our reportable operating segments are—Merchant Energy, Regulated Electric, and Regulated Gas:

        We have restated certain prior-period information for comparative purposes based on our reportable operating segments.

        Effective July 1, 2000, the financial results of the electric generation portion of our business are included in the merchant energy business segment. Prior to that date, the financial results of electric generation are included in our regulated electric business.

        Our remaining nonregulated businesses:

        These reportable segments are strategic businesses based principally upon regulations, products, and services that require different technology and marketing strategies. We evaluate the performance of these segments based on net income. We account for intersegment revenues using market prices. A summary of information by operating segment is shown on the next page.

72

 
   Merchant Energy Business
   Regulated Electric Business
   Regulated Gas Business
   Other Nonregulated Businesses
   Unallocated Corporate Items and Eliminations
   Consolidated
 
   (In millions)
2001                                    
Unaffiliated revenues   $ 614.3   $ 2,039.6   $ 674.3   $ 600.1   $ —   $ 3,928.3
Intersegment revenues     1,151.2     0.4     6.4     2.0     (1,160.0 )   —
Total revenues     1,765.5     2,040.0     680.7     602.1     (1,160.0 )   3,928.3
Depreciation and amortization     174.9     173.3     47.7     23.2     —     419.1
Fixed charges     25.8     135.8     28.5     48.7     —     238.8
Income tax expense (benefit)     25.2     36.8     25.7     (49.8 )   —     37.9
Cumulative effect of change in accounting principle     —     —     —     8.5     —     8.5
Net income (loss) (a)     93.1     50.9     37.5     (90.6 )   —     90.9
Segment assets     8,134.3     3,764.9     1,104.2     1,314.0     (239.8 )   14,077.6
Capital expenditures     1,815.0     180.3     58.7     35.0     —     2,089.0

2000
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unaffiliated revenues   $ 421.1   $ 2,134.7   $ 603.8   $ 692.9   $ —   $ 3,852.5
Intersegment revenues     604.6     0.5     7.8     20.4     (633.3 )   —
Total revenues     1,025.7     2,135.2     611.6     713.3     (633.3 )   3,852.5
Depreciation and amortization     83.6     319.9     46.2     20.3     —     470.0
Equity in income of equity-method investees (b)     —     2.4     —     —     —     2.4
Fixed charges     18.3     168.4     27.3     65.8     (8.4 )   271.4
Income tax expense     118.5     72.2     21.9     17.5     —     230.1
Net income (c)     198.6     102.3     30.6     13.8     —     345.3
Segment assets     7,295.5     3,392.3     1,089.9     1,491.5     (329.9 )   12,939.3
Capital expenditures     699.0     290.3     59.7     131.5     —     1,180.5

1999
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unaffiliated revenues   $ 277.3   $ 2,258.8   $ 476.5   $ 828.3   $ —   $ 3,840.9
Intersegment revenues     —     1.2     11.6     20.1     (32.9 )   —
Total revenues     277.3     2,260.0     488.1     848.4     (32.9 )   3,840.9
Depreciation and amortization     7.5     376.4     44.9     21.0     —     449.8
Equity in income of equity-method investees (b)     —     5.1     —     —     —     5.1
Fixed charges     —     174.2     26.1     56.1     (1.4 )   255.0
Income tax expense (benefit)     29.2     149.2     18.1     (10.1 )   —     186.4
Extraordinary loss     —     66.3     —     —     —     66.3
Net income (loss) (d)     52.4     198.8     33.0     (24.1 )   —     260.1
Segment assets     1,259.0     6,312.6     915.3     1,239.7     18.5     9,745.1
Capital expenditures     163.0     366.8     69.2     115.2     —     714.2

        (a) Our merchant energy business, our regulated electric business, our regulated gas business, and our other nonregulated businesses recognized $198.1 million, $33.6 million, $0.8 million, and $102.3 million, respectively, for workforce reduction costs, contract termination related costs, and impairment losses and other costs as described more fully in Note 2.

        (b) Our merchant energy business records its equity in the income of equity method investees in unaffiliated revenues.

        (c) Our regulated electric business recorded expense of $4.2 million related to employees that elected to participate in a Voluntary Special Early Retirement Program. In addition, our merchant energy business recorded a $15.0 million deregulation transition cost incurred by our power marketing operation.

        (d) Our regulated electric business recorded expense of $4.9 million related to Hurricane Floyd. Our merchant energy business recorded $14.2 million for the impairment of two geothermal power plants. Our Latin American operation recorded $4.5 million for the impairment to reflect the fair value of our investment in a power project in Bolivia. Our financial investments operation recorded $16.0 million for the reduction of its investment in Capital Re stock to reflect the market value of this investment. Our real estate and senior-living facilities operation recorded $5.8 million for the impairment of certain senior-living facilities.

73

4 Investments

Real Estate Projects and Investments

Real estate projects and investments held by Constellation Real Estate Group (CREG), consist of the following:

At December 31,

   2001
   2000
 
   (In millions)
Properties under development   $ 100.5   $ 165.1
Operating properties
(net of accumulated depreciation)		     0.9     12.7
Equity interest in real estate investments     109.3     112.5
Total real estate projects and investments   $ 210.7   $ 290.3

        See Note 2 for a discussion of impairments recorded in 2001.


Power Projects

Investments in power projects held by our merchant energy business consist of the following:

At December 31,

   2001
   2000
 
   (In millions)
Equity Method   $ 480.3   $ 488.4
Cost Method     10.7     10.8
Total power projects   $ 491.0   $ 499.2

        Our percentage voting interest in power projects accounted for under the equity method ranges from 16% to 50%. Equity in earnings of these power projects were $24.2 million in 2001, $50.2 million in 2000, and $49.7 million in 1999.

        Our power projects accounted for under the equity method include investments of $296.4 million in 2001 and $297.9 million in 2000 that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. We discuss these projects further in Note 11.

        Our Latin American operation held power projects of $8.1 million at December 31, 2001 and $11.4 million at December 31, 2000.

        See Note 2 for a discussion of impairments recorded in 2001.


Orion and Financial Investments

Financial investments consist of the following:

At December 31,

   2001
   2000
 
   (In millions)
Orion   $ 442.5   $ 192.0
Marketable equity securities     20.2     105.9
Financial limited partnerships     25.8     32.7
Leveraged leases     14.7     22.4
Total financial investments   $ 503.2   $ 353.0


Investments Classified as Available-for-Sale

We classify the following investments as available-for-sale:

        This means we do not expect to hold them to maturity, and we do not consider them trading securities.

        Effective June 1, 2001, we changed our accounting for the investment in Orion from the equity method to the cost method. This change resulted from no longer having significant influence as required under equity method accounting due to a reduction in our ownership percentage. Our ownership percentage decreased due to Orion's issuance of 13 million shares of common stock that were sold in a public offering and due to our sale of one million shares as part of the offering. At December 31, 2001, the unrealized gain on our investment in Orion was $244.0 million. In addition, at December 31, 2001, we owned a warrant for 705,900 shares of common stock in Orion with a fair market value of $11.8 million. These warrants are accounted for under SFAS No. 133 as discussed in Note 1.

        We show the fair values, gross unrealized gains and losses, and amortized cost bases for all of our available-for-sale securities, in the following tables. We use specific identification to determine cost in computing realized gains and losses, except we use average cost basis for our investment in Orion.

At December 31, 2001

   Amortized Cost Basis
   Unrealized Gains
   Unrealized Losses
   Fair Value
 
   (In millions)
Marketable equity securities   $ 773.9   $ 270.6   $ (10.3 ) $ 1,034.2
Corporate debt and U.S. Government agency     47.7     1.5     —     49.2
State municipal bonds     38.4     3.3     (0.2 )   41.5
Totals   $ 860.0   $ 275.4   $ (10.5 ) $ 1,124.9
At December 31, 2000

   Amortized Cost Basis
   Unrealized Gains
   Unrealized Losses
   Fair Value
 
   (In millions)
Marketable equity securities   $ 171.8   $ 68.9   $ (2.2 ) $ 238.5
Corporate debt and U.S. Government agency     26.1     0.1     (0.1 )   26.1
State municipal bonds     61.3     2.3     (0.4 )   63.2
Totals   $ 259.2   $ 71.3   $ (2.7 ) $ 327.8

        In addition to the above securities, the nuclear decommissioning trust funds included $7.7 million at December 31, 2001 and $6.8 million at December 31, 2000 of cash and cash equivalents.

74


        The preceding tables include $21.0 million in 2001 and $34.7 million in 2000 of unrealized net gains associated with the nuclear decommissioning trust funds that are reflected as a change in the nuclear decommissioning trust funds in our Consolidated Balance Sheets.

        Gross and net realized gains and losses on available-for-sale securities were as follows:

 
   2001
   2000
   1999
  
 
 
   (In millions)

  
Gross realized gains   $ 47.6   $ 54.5   $ 11.7  
Gross realized losses     (7.9 )   (8.0 )   (38.8 )
 
Net realized gains (losses)   $ 39.7   $ 46.5   $ (27.1 )
 

        The corporate debt securities, U.S. Government agency obligations, and state municipal bonds mature on the following schedule:

At December 31, 2001

   Amount
 
   (In millions)
Less than 1 year   $ 8.4
1-5 years     34.3
5-10 years     22.2
More than 10 years     25.8
Total maturities of debt securities   $ 90.7

5 Rate Matters and Accounting Impacts of Deregulation

On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition Act of 1999 (the "Act") and accompanying tax legislation that significantly restructured Maryland's electric utility industry and modified the industry's tax structure. In the Restructuring Order discussed below, the Maryland PSC addressed the major provisions of the Act.

        The tax legislation made comprehensive changes to the state and local taxation of electric and gas utilities. Effective January 1, 2000, the Maryland public service franchise tax was altered to generally include a tax equal to .062 cents on each kilowatt-hour of electricity and .402 cents on each therm of natural gas delivered for final consumption in Maryland. The Maryland 2% franchise tax on electric and natural gas utilities continues to apply to transmission and distribution revenue. Additionally, all electric and natural gas utility results are subject to the Maryland corporate income tax.

        Beginning July 1, 2000, the tax legislation also provided for a two-year phase-in of a 50% reduction in the local personal property taxes on machinery and equipment used to generate electricity for resale and a 60% corporate income tax credit for real property taxes paid on those facilities.

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

75

        As discussed in Note 1, EITF 97-4 requires that a company should cease applying SFAS No. 71 when either legislation is passed or a regulatory body issues an order that contains sufficient detail to determine how the transition plan will affect the deregulated portion of the business. Additionally, a company would continue to recognize regulatory assets and liabilities in the Consolidated Balance Sheets to the extent that the transition plan provides for their recovery.

        We believe that the Restructuring Order provided sufficient details of the transition plan to competition for BGE's electric generation business to require BGE to discontinue the application of SFAS No. 71 for that portion of its business. Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101 and EITF 97-4 for BGE's electric generation business.

        SFAS No. 101 requires the elimination of the effects of rate regulation that have been recognized as regulatory assets and liabilities pursuant to SFAS No. 71. However, EITF 97-4 requires that regulatory assets and liabilities that will be recovered in the regulated portion of the business continue to be classified as regulatory assets and liabilities. The Restructuring Order provided for the creation of a single, new generation-related regulatory asset to be recovered through BGE's regulated transmission and distribution business. We discuss this further in Note 6.

        Pursuant to SFAS No. 101, the book value of property, plant and equipment may not be adjusted unless those assets are impaired under the provisions of SFAS No. 121. The process we used in evaluating and measuring impairment under the provisions of SFAS No. 121 involved two steps. First, we compared the net book value of each generating plant to the estimated undiscounted future net operating cash flows from that plant. An electric generating plant was considered impaired when its undiscounted future net operating cash flows were less than its net book value. Second, we computed the fair value of each plant that is determined to be impaired based on the present value of that plant's estimated future net operating cash flows discounted using an interest rate that considers the risk of operating that facility in a competitive environment. To the extent that the net book value of each impaired electric generation plant exceeded its fair value, we reduced its book value.

        Under the Restructuring Order, BGE will recover $528 million after-tax of its potentially stranded investments and utility restructuring costs through the competitive transition charge component of its customer rates beginning July 1, 2000. This recovery mostly relates to the stranded costs associated with the Calvert Cliffs Nuclear Power Plant, whose book value was substantially higher than its estimated fair value. However, Calvert Cliffs was not considered impaired under the provisions of SFAS No. 121 since its estimated future undiscounted cash flows exceeded its book value. Accordingly, BGE did not record any impairment related to Calvert Cliffs. However, BGE recognized after-tax impairment losses totaling $115.8 million associated with certain of its fossil plants under the provisions of SFAS No. 121.

        BGE had contracts to purchase electric capacity and energy that became uneconomic upon the deregulation of electric generation. Therefore, BGE recorded a $34.2 million after-tax charge based on the net present value of the excess of estimated contract costs over the market-based revenues to recover these costs over the remaining terms of the contracts. In addition, BGE had deferred certain energy conservation expenditures that would not be recovered through its transmission and distribution business under the Restructuring Order. Accordingly, BGE recorded a $10.3 million after-tax charge to eliminate the regulatory asset previously established for these deferred expenditures.

        At December 31, 1999, the total charge for BGE's electric generating plants that were impaired, losses on uneconomic purchased capacity and energy contracts, and deferred energy conservation expenditures was approximately $160.3 million after-tax.

        BGE recorded approximately $94.0 million of the $160.3 million on its balance sheet. This consisted of a $150.0 million regulatory asset of its regulated transmission and distribution business, net of approximately $56.0 million of associated deferred income taxes. The regulatory asset was amortized as it was recovered from ratepayers through June 30, 2000. This accomplished the $150 million reduction of its generation plants required by the Restructuring Order.

        BGE recorded an after-tax, extraordinary charge against earnings for approximately $66.3 million related to the remaining portion of the $160.3 million described above that was not recovered under the Restructuring Order.

76

6 Regulatory Assets (net)

As discussed in Note 1, the Maryland PSC provides the final determination of the rates we charge our customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under accounting principles generally accepted in the United States of America. However, sometimes the Maryland PSC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers. When this happens, we must defer certain utility expenses and income in our Consolidated Balance Sheets as regulatory assets and liabilities. We then record them in our Consolidated Statements of Income (using amortization) when we include them in the rates we charge our customers.

        We summarize regulatory assets and liabilities in the following table, and we discuss each of them separately below.

At December 31,

   2001
   2000
 
   (In millions)
Electric generation-related regulatory asset   $ 249.0   $ 267.8
Income taxes recoverable through future rates (net)     95.6     101.2
Deferred postretirement and postemployment benefit costs     35.5     38.7
Deferred environmental costs     26.0     28.8
Deferred fuel costs (net)     33.5     71.1
Workforce reduction costs     21.6     2.8
Other (net)     2.6     4.5
Total regulatory assets (net)   $ 463.8   $ 514.9


Electric Generation-Related Regulatory Asset

With the issuance of the Restructuring Order, BGE no longer met the requirements for the application of SFAS No. 71 for the electric generation portion of its business. In accordance with SFAS No. 101 and EITF 97-4, all individual generation-related regulatory assets and liabilities must be eliminated from our balance sheet unless these regulatory assets and liabilities will be recovered in the regulated portion of the business. Pursuant to the Restructuring Order, BGE wrote-off all of its individual, generation-related regulatory assets and liabilities. BGE established a single, new generation-related regulatory asset for amounts to be collected through its regulated transmission and distribution business. The new regulatory asset is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules.


Income Taxes Recoverable Through Future Rates (net)

As described in Note 1, income taxes recoverable through future rates are the portion of our net deferred income tax liability that is applicable to our regulated utility business, but has not been reflected in the rates we charge our customers. These income taxes represent the tax effect of temporary differences in depreciation and the allowance for equity funds used during construction, offset by differences in deferred tax rates and deferred taxes on deferred investment tax credits. We amortize these amounts as the temporary differences reverse.


Deferred Postretirement and Postemployment Benefit Costs

Deferred postretirement and postemployment benefit costs are the costs we recorded under SFAS No. 106 (for postretirement benefits) and No. 112 (for postemployment benefits) in excess of the costs we included in the rates we charge our customers. We began amortizing these costs over a 15-year period in 1998. We discuss these costs further in Note 7.


Deferred Environmental Costs

Deferred environmental costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss this further in Note 11. We are amortizing $21.6 million of these costs (the amount we had incurred through October 1995) and $6.4 million of these costs (the amount we incurred from November 1995 through June 2000) over 10-year periods in accordance with the Maryland PSC's orders.


Deferred Fuel Costs

As described in Note 1, deferred fuel costs are the difference between our actual costs of electric fuel, net purchases and sales of electricity, and natural gas, and our fuel rate revenues collected from customers. We reduce deferred fuel costs as we collect them from or refund them to our customers.

        We show our deferred fuel costs in the following table.

At December 31,

   2001
   2000
 
   (In millions)
Electric   $ —   $ 42.3
Gas     33.5     28.8
Deferred fuel costs (net)   $ 33.5   $ 71.1

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


Workforce Reduction Costs

The portions of the workforce reduction costs associated with the VSERP and involuntary severance programs we announced in 2001 and 2000 that relate to BGE's gas business are deferred as regulatory assets in accordance with the Maryland PSC's orders in prior rate cases. These costs are amortized over 5-year periods. See Note 2 and Note 7.

77

7 Pension, Postretirement, Other Postemployment, and Employee Savings Plan Benefits

We offer pension, postretirement, other postemployment, and employee savings plan benefits. We describe each of these separately below. Nine Mile Point offers its own pension, postretirement, other postemployment, and employee savings plan benefits to its employees. The benefits for Nine Mile Point are included in the tables beginning on the next page.


Pension Benefits

We sponsor several defined benefit pension plans for our employees. These include the basic, qualified plan that most employees participate in and several nonqualified plans that are available only to certain employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. Employees do not contribute to these plans. Generally, we calculate the benefits under these plans based on age, years of service, and pay.

        Sometimes we amend the plans retroactively. These retroactive plan amendments require us to recalculate benefits related to participants' past service. We amortize the change in the benefit costs from these plan amendments on a straight-line basis over the average remaining service period of active employees.

        We fund the plans by contributing at least the minimum amount required under Internal Revenue Service regulations. We calculate the amount of funding using an actuarial method called the projected unit credit cost method. The assets in all of the plans at December 31, 2001 were mostly marketable equity and fixed income securities.

        In 1999, we made the following amendments:

        The financial impacts of the amendments are included in the tables beginning on the next page.


Postretirement Benefits

We sponsor defined benefit postretirement health care and life insurance plans that cover substantially all of our employees. Generally, we calculate the benefits under these plans based on age, years of service, and pension benefit levels. We do not fund these plans.

        For nearly all of the health care plans, retirees make contributions to cover a portion of the plan costs.

        Contributions for employees who retire after June 30, 1992 are calculated based on age and years of service. The amount of retiree contributions increases based on expected increases in medical costs. For the life insurance plan, retirees do not make contributions to cover a portion of the plan costs.

        Effective January 1, 1993, we adopted SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. The adoption of that statement caused:

        For our nonregulated businesses, we expense all postretirement benefit costs. For our regulated utility business, we accounted for the increase in annual postretirement benefit costs under two Maryland PSC rate orders:

        Beginning in 1998, the Maryland PSC authorized us to:


VSERP

In 2001, our Board of Directors approved several voluntary retirement programs for Constellation Energy and certain subsidiaries. The first group of these programs offered enhanced early retirement benefits to employees age 55 or older with 10 or more years of service. The second group of these programs offered enhanced early retirement benefits to employees age 50 to 54 with 20 or more years of service.

        Since employees electing to participate in the age 55 or older VSERP had to make their elections by the end of 2001, the cost of that program was reflected in 2001. The total cost of that program was approximately $83.8 million ($63.5 million in pension termination benefits, $18.5 million in postretirement benefit costs, and $1.8 million in education and outplacement assistance costs). Of this amount, BGE recorded approximately $13.7 million on its balance sheet as a regulatory asset of its gas business. This amount will be amortized over a 5-year period as provided for in prior Maryland PSC rate orders.

        In connection with the retirement of a significant number of the participants in the nonqualified pension plans we recognized a settlement loss of approximately $10.5 million and a curtailment loss of approximately $5.8 million for those plans in accordance with SFAS No. 88.

        Since the age 50 to 54 programs allow employees to make their elections beginning in January through February 2002, the cost of that program will be reflected in 2002.

78

        We recorded a $133.0 million additional minimum pension liability adjustment as a result of the combination of decreases in the fair value of plan assets due to a declining equity market in 2001 and an increased pension liability primarily due to the VSERP. We charged $59.0 million of this adjustment to an intangible asset included in "Other deferred charges" in our Consolidated Balance Sheets. The remaining $74.0 million, or $44.7 million after-tax, of this adjustment was included in "Accumulated other comprehensive income" in our Consolidated Statements of Common Shareholders' Equity and Consolidated Statements of Capitalization.

        In 2000, we offered a targeted VSERP to provide enhanced early retirement benefits to certain eligible participants in targeted jobs at BGE that elected to retire on June 1, 2000. BGE recorded approximately $10.0 million ($7.6 million for pension termination benefits and $2.4 million for postretirement benefit costs) for employees that elected to participate in the program. Of this amount, BGE recorded approximately $3.0 million on its balance sheet as a regulatory asset of its gas business. We amortize this regulatory asset over a 5-year period. The remaining $7.0 million related to BGE's electric business was charged to expense.

        The cost of the 2001 and 2000 voluntary retirement programs and the settlement or curtailment losses are not included in the tables of net periodic pension and postretirement benefit costs.


Obligations, Assets, and Funded Status

We show the change in the benefit obligations, plan assets, and funded status of the pension and postretirement benefit plans including the effect of the Nine Mile Point acquisition, in the following tables.

 
   Pension
Benefits

   Postretirement
Benefits

  
 
   2001
   2000
   2001
   2000
  
 
 
   (In millions)

  
Change in benefit obligation              
Benefit obligation at January 1   $ 1,045.1   $ 1,016.7   $ 375.9   $ 358.7  
Service cost     25.8     25.4     8.4     7.7  
Interest cost     76.1     73.1     29.2     26.6  
Plan participants' contributions     —     —     3.0     2.8  
Actuarial loss     42.6     0.8     49.1     40.9  
Plan amendments     —     6.7     —     (41.1 )
VSERP charge     63.5     7.6     18.5     2.4  
Curtailment     9.7     —     —     —  
Settlement     (23.0 )   —     —     —  
Nine Mile Point acquisition     91.8     —     15.0     —  
Benefits paid     (72.4 )   (85.2 )   (23.9 )   (22.1 )
 
Benefit obligation at December 31   $ 1,259.2   $ 1,045.1   $ 475.2   $ 375.9  
 
 
   Pension
Benefits

   Postretirement
Benefits

  
 
   2001
   2000
   2001
   2000
  
 
 
   (In millions)

  
Change in plan assets                          
Fair value of plan assets at January 1   $ 1,030.1   $ 1,084.9   $ —   $ —  
Actual return on plan assets     (42.7 )   3.7     —     —  
Employer contribution     39.4     26.7     20.9     19.3  
Plan participants' contributions     —     —     3.0     2.8  
Benefits paid     (72.4 )   (85.2 )   (23.9 )   (22.1 )
 
Fair value of plan assets at December 31   $ 954.4   $ 1,030.1   $ —   $ —  
 
 
   Pension
Benefits

   Postretirement
Benefits

  
 
   2001
   2000
   2001
   2000
  
 
 
   (In millions)

  
Funded Status                          
Funded Status at December 31   $ (304.8 ) $ (15.0 ) $ (475.2 ) $ (375.9 )
Unrecognized net actuarial loss     207.8     49.2     107.8     61.4  
Unrecognized prior service cost     56.7     59.2     (0.4 )   (0.4 )
Unrecognized transition obligation     —     —     86.9     94.8  
Unamortized net asset from adoption of SFAS No. 87     —     (0.2 )   —     —  
Pension liability adjustment     (133.0 )   —     —     —  
 
(Accrued) prepaid benefit cost   $ (173.3 ) $ 93.2   $ (280.9 ) $ (220.1 )
 

79


Net Periodic Benefit Cost

We show the components of net periodic pension benefit cost in the following table:

Year Ended December 31,

   2001
   2000
   1999
  
 
 
   (In millions)

  
Components of net periodic pension benefit cost                    
Service cost   $ 25.8   $ 25.4   $ 26.1  
Interest cost     76.1     73.1     65.3  
Expected return on plan assets     (87.5 )   (83.6 )   (76.6 )
Amortization of transition obligation     (0.2 )   (0.2 )   (0.2 )
Amortization of prior service cost     6.5     6.5     2.5  
Recognized net actuarial loss     2.8     2.6     10.1  
Amount capitalized as construction cost     (2.5 )   (3.4 )   (4.2 )
 
Net periodic pension benefit cost   $ 21.0   $ 20.4   $ 23.0  
 

        We show the components of net periodic postretirement benefit cost in the following table:

Year Ended December 31,

   2001
   2000
   1999
  
 
 
   (In millions)

  
Components of net periodic postretirement benefit cost                    
Service cost   $ 8.4   $ 7.7   $ 8.6  
Interest cost     29.2     26.6     24.4  
Amortization of transition obligation     7.9     7.9     11.0  
Recognized net actuarial loss     3.3     3.1     1.9  
Amount capitalized as construction cost     (14.5 )   (10.8 )   (9.4 )
 
Net periodic postretirement benefit cost   $ 34.3   $ 34.5   $ 36.5  
 


Assumptions

We made the assumptions below to calculate our pension and postretirement benefit obligations.

 
   Pension
Benefits

   Postretirement
Benefits

    
  
At December 31,

    
  
  2001
   2000
   2001
   2000
    
  
 
Discount rate   7.25 % 7.50 % 7.25 % 7.50 %    
Expected return on plan assets   9.00   9.00   N/A   N/A      
Rate of compensation increase   4.00   4.00   4.00   4.00      

        We assumed the health care inflation rates to be:

        After 2002, we assumed inflation rates will decrease to 7.0% in 2003, 6.5% in 2004, 6.0% in 2005, and 5.5% annually after 2005.

        A one-percent increase in the health care inflation rate from the assumed rates would increase the accumulated postretirement benefit obligation by approximately $63.8 million as of December 31, 2001 and would increase the combined service and interest costs of the postretirement benefit cost by approximately $5.9 million annually.

        A one-percent decrease in the health care inflation rate from the assumed rates would decrease the accumulated postretirement benefit obligation by approximately $51.1 million as of December 31, 2001 and would decrease the combined service and interest costs of the postretirement benefit cost by approximately $4.7 million annually.


Other Postemployment Benefits

We provide the following postemployment benefits:

        The liability for these benefits totaled $48.7 million as of December 31, 2001 and $46.7 million as of December 31, 2000.

        Effective December 31, 1993, we adopted SFAS No. 112, Employers' Accounting for Postemployment Benefits. We deferred, as a regulatory asset (see Note 6), the postemployment benefit liability attributable to our regulated utility business as of December 31, 1993, consistent with the Maryland PSC's orders for postretirement benefits (described earlier in this note).

        We began to amortize the regulatory asset over 15 years beginning in 1998. The Maryland PSC authorized us to reflect this change in our regulated electric and gas base rates to recover the higher costs in 1998.

        We assumed the discount rate for other postemployment benefits to be 5.0% in 2001 and 5.5% in 2000.


Employee Savings Plan Benefits

We, along with several of our subsidiaries, sponsor defined contribution savings plans that are offered to all eligible employees of Constellation Energy and certain employees of our subsidiaries. The Savings Plans are qualified 401(k) plans under the Internal Revenue Code. In a defined contribution plan, the benefits a participant is to receive result from regular contributions to a participant account. Matching contributions to participant accounts are made under these plans. Matching contributions to these plans were:

80


Constellation Energy

In anticipation of separating our merchant energy business from our other businesses and to fund working capital requirements and capital expenditures, in June 2001, Constellation Energy arranged a $2.5 billion, 364-day revolving credit facility. However, since we canceled prior plans to separate, we used this facility primarily to fund capital expenditures, and working capital requirements, including commercial paper support, for the merchant energy business.

        In June 2001, Constellation Energy also arranged a $380 million, 364-day revolving credit facility to be used primarily to support letters of credit and for other short-term financing needs, including commercial paper support. Constellation Energy also has an existing $188.5 million, multi-year revolving credit facility available for short-term and long-term needs, including support for the issuance of letters of credit.

        Constellation Energy had committed bank lines of credit as described above of $3.1 billion at December 31, 2001 and $565.0 million at December 31, 2000 for short-term financial needs, including support for the issuance of letters of credit. These agreements also support Constellation Energy's commercial paper program. Letters of credit issued under all of our facilities totaled $245.8 million at December 31, 2001 and $297.2 million at December 31, 2000. Constellation Energy had commercial paper outstanding of $954.9 million at December 31, 2001 and $198.7 million at December 31, 2000.

        The weighted-average effective interest rates for Constellation Energy's commercial paper were 3.73% for the year ended December 31, 2001 and 6.31% for 2000.


BGE

BGE had no commercial paper outstanding at December 31, 2001 and $32.1 million at December 31, 2000.

        At December 31, 2001, BGE had unused committed bank lines of credit totaling $243.0 million supporting the commercial paper program compared to $218.0 million at December 31, 2000. BGE has a $25 million revolving credit agreement that is available through 2003. At December 31, 2001 and 2000, BGE did not have any borrowings under the revolving credit agreement. This agreement also supports BGE's commercial paper program.

        The weighted-average effective interest rates for BGE's commercial paper were 2.53% for the year ended December 31, 2001 and 6.36% for 2000.


Other Nonregulated Businesses

Our other nonregulated businesses had short-term borrowings outstanding of $20.1 million at December 31, 2001 and $12.8 million at December 31, 2000. The weighted-average effective interest rates for our other nonregulated businesses' short-term borrowings were 4.20% for the year ended December 31, 2001 and 8.59% for 2000.

9 Long-Term Debt

Long-term debt matures in one year or more from the date of issuance. We summarize our long-term debt in the Consolidated Statements of Capitalization. As you read this section, it may be helpful to refer to those statements.


Constellation Energy

On January 17, 2001, we issued $400.0 million of Mandatorily Redeemable Floating Rate Notes that matured on January 17, 2002.

        On April 11, 2001, we issued $235.0 million of Mandatorily Redeemable Floating Rate Notes that matured on January 17, 2002.

        In 2001, we redeemed several Notes that totaled $700.0 million prior to their maturity for a purchase price equal to 100% of their principal amount, plus accrued interest.


BGE

BGE's First Refunding Mortgage Bonds

BGE's first refunding mortgage bonds are secured by a mortgage lien on all of its assets. The generating assets BGE transferred to subsidiaries of Constellation Energy also remain subject to the lien of BGE's mortgage, along with the stock of Safe Harbor Water Power Corporation and Constellation Enterprises, Inc.

        BGE is required to make an annual sinking fund payment each August 1 to the mortgage trustee. The amount of the payment is equal to 1% of the highest principal amount of bonds outstanding during the preceding 12 months. The trustee uses these funds to retire bonds from any series through

81

repurchases or calls for early redemption. However, the trustee cannot call the following bonds for early redemption:

• 71/4% Series, due 2002   • 51/2% Series, due 2004
• 61/2% Series, due 2003   • 71/2% Series, due 2007
• 61/8% Series, due 2003   • 65/8% Series, due 2008

        Holders of the Remarketed Floating Rate Series due September 1, 2006 have the option to require BGE to repurchase their bonds at face value on September 1 of each year. BGE is required to repurchase and retire at par any bonds that are not remarketed or purchased by the remarketing agent. BGE also has the option to redeem all or some of these bonds at face value each September 1.

BGE's Other Long-Term Debt

On May 11, 2001, BGE issued $200.0 million of Floating Rate Reset Notes that matured on February 5, 2002.

        Also on May 11, 2001, BGE redeemed $200.0 million of Floating Rate Notes.

        On December 11, 2001, BGE issued $300.0 million 5.25% Notes, due December 15, 2006.

        On July 1, 2000, BGE transferred $278.0 million of tax-exempt debt to our merchant energy business related to the transferred assets. At December 31, 2001, BGE remains contingently liable for the $276.5 million outstanding balance of this debt.

        On December 20, 2000, BGE issued $173.0 million of 6.75% Remarketable and Redeemable Securities (ROARS) due December 15, 2012. The ROARS contain an option for the underwriters to remarket the ROARS on December 15, 2002. If the underwriters do not elect to remarket the ROARS on that date, then BGE must redeem the ROARS at 100% of the principal amount on December 15, 2002.

        We show the weighted-average interest rates and maturity dates for BGE's fixed-rate medium-term notes outstanding at December 31, 2001 in the following table.

Series
   Weighted-Average Interest Rate
   Maturity Dates
B   8.77 % 2002-2006
C   7.97   2003
D   6.67   2004-2006
E   6.66   2006-2012
G   6.08   2008

        Some of the medium-term notes include a "put option." These put options allow the holders to sell their notes back to BGE on the put option dates at a price equal to 100% of the principal amount. The following is a summary of medium-term notes with put options.

Series E Notes
  Principal
   Put Option Dates
(In millions)
6.75%, due 2012   $ 60.0   June 2002 and 2007
6.75%, due 2012   $ 25.0   June 2004 and 2007
6.73%, due 2012   $ 25.0   June 2004 and 2007

BGE Obligated Mandatorily Redeemable Trust Preferred Securities

On June 15, 1998, BGE Capital Trust I (Trust), a Delaware business trust established by BGE, issued 10,000,000 Trust Originated Preferred Securities (TOPrS) for $250 million ($25 liquidation amount per preferred security) with a distribution rate of 7.16%.

        The Trust used the net proceeds from the issuance of the common securities and the preferred securities to purchase a series of 7.16% Deferrable Interest Subordinated Debentures due June 30, 2038 (debentures) from BGE in the aggregate principal amount of $257.7 million with the same terms as the TOPrS. The Trust must redeem the TOPrS at $25 per preferred security plus accrued but unpaid distributions when the debentures are paid at maturity or upon any earlier redemption. BGE has the option to redeem the debentures at any time on or after June 15, 2003 or at any time when certain tax or other events occur.

        The interest paid on the debentures, which the Trust will use to make distributions on the TOPrS, is included in "Interest expense" in our Consolidated Statements of Income and is deductible for income tax purposes.

        BGE fully and unconditionally guarantees the TOPrS based on its various obligations relating to the trust agreement, indentures, debentures, and the preferred security guarantee agreement.

        The debentures are the only assets of the Trust. The Trust is wholly owned by BGE because it owns all the common securities of the Trust that have general voting power.

        For the payment of dividends and in the event of liquidation of BGE, the debentures are ranked prior to preference stock and common stock.


Other Nonregulated Businesses

Revolving Credit Agreement

ComfortLink has a $50 million unsecured revolving credit agreement that matures September 26, 2002. Under the terms of the agreement, ComfortLink has the option to obtain loans at various rates for terms up to nine months. ComfortLink pays a facility fee on the total amount of the commitment. Under this agreement, ComfortLink had outstanding $46.0 million at December 31, 2001 and $34.0 million at December 31, 2000.

        On December 18, 2001, ComfortLink entered into a $25.0 million loan agreement with the Maryland Energy Financing Administration (MEFA). The terms of the loan exactly match the terms of variable rate, tax exempt bonds due December 1, 2031 issued by MEFA for ComfortLink to finance the cost of building a chilled water distribution system. The interest rate on this debt resets weekly. These bonds, and the corresponding loan, can be redeemed at any time at par plus accrued interest while under variable rates. The bonds can also be converted to a fixed rate at ComfortLink's option.

82

Mortgage and Construction Loans

Our nonregulated businesses' mortgage and construction loans have varying terms. The following mortgage notes require monthly principal and interest payments:

        The variable rate mortgage notes and construction loans require periodic payment of principal and interest.


Maturities of Long-Term Debt

All of our long-term borrowings mature on the following schedule (includes sinking fund requirements):

Year

   Constellation Energy
   Nonregulated Business
   BGE
 
   (In millions)
2002   $ 635.0   $ 85.4   $ 519.8
2003     —     86.1     285.6
2004     —     83.7     155.4
2005     300.0     78.4     46.9
2006     —     78.4     464.9
Thereafter     —     357.1     947.7
Total long-term debt at December 31, 2001   $ 935.0   $ 769.1   $ 2,420.3

        At December 31, 2001, BGE had long-term loans totaling $221.5 million that mature after 2002 (including $110.0 million of medium-term notes discussed in this Note under "BGE's Other Long-Term Debt") which contain certain put options under which lenders could potentially require us to repay the debt prior to maturity. Of this amount, $171.5 million could be repaid in 2002 and $50.0 million in 2004. At December 31, 2001, $146.5 million is classified as current portion of long-term debt as a result of these provisions.

        At December 31, 2001, our other nonregulated businesses had long-term loans totaling $20.0 million that mature after 2003 that lenders could potentially require us to repay early. This amount is classified as current portion of long-term debt as a result of these repayment provisions.


Weighted-Average Interest Rates for Variable Rate Debt

Our weighted-average interest rates for variable rate debt were:

Year ended December 31,

   2001
   2000
    
  
 
Nonregulated Businesses
(including Constellation Energy)		              
  Floating rate notes   4.95 % 6.98 %    
  Loans under credit agreements   4.60   6.64      
  Mortgage and construction loans   4.39   7.78      
  Tax-exempt debt transferred from BGE   3.12   4.26      
  Other tax-exempt debt   1.75   —      
BGE              
  Remarketed floating rate series mortgage bonds   4.49 % 6.59 %    
  Floating rate reset notes   4.14   7.27      
  Medium-term notes, Series G   —   6.58      
  Medium-term notes, Series H   —   6.58      

10 Leases

There are two types of leases—operating and capital. Capital leases qualify as sales or purchases of property and are reported in our Consolidated Balance Sheets. Capital leases are not material in amount. All other leases are operating leases and are reported in our Consolidated Statements of Income. We expense all lease payments associated with our regulated utility operations. We present information about our operating leases below.


Outgoing Lease Payments

We, as lessee, lease some facilities and equipment. The lease agreements expire on various dates and have various renewal options.

        Lease expense was:

        At December 31, 2001, we owed future minimum payments for long-term, noncancelable, operating leases as follows:

Year

    
 
   (In millions)
2002   $ 9.1
2003     24.1
2004     39.2
2005     37.9
2006     13.3
Thereafter     145.8
Total future minimum lease payments   $ 269.4

        The above table includes the operating lease payments for the High Desert project in California through 2006. We are currently leasing and supervising the construction of the High Desert project, a 750 megawatt generating facility in California. The High Desert project uses an off-balance sheet financing structure through a special-purpose entity (SPE) that qualifies as

83

an operating lease. The project is scheduled for completion in the summer of 2003.

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

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

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

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

11 Commitments, Guarantees, and Contingencies

Commitments

We have made substantial commitments in connection with our merchant energy, regulated gas, and other nonregulated business. These commitments relate to:

        Our merchant energy business has a long-term contract for the purchase of electric generating capacity and energy that expires in 2013. Portions of this contract became uneconomical upon the deregulation of electric generation. Therefore, we recorded a charge and accrued a corresponding liability based on the net present value of the excess of estimated contract costs over the market-based revenues to recover these costs over the remaining term of the contract as discussed in Note 5. At December 31, 2001, the accrued portion of this contract was $10.6 million.

        Our merchant energy business enters into various long-term contracts for the procurement and delivery of fuels to supply our generating plant requirements. In most cases, our contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. These contracts expire in various years between 2002 and 2006. In addition, our merchant energy business enters into long-term contracts for the capacity and transmission rights for the delivery of energy to meet our physical obligations to our customers. These contracts expire in various years between 2002 and 2021.

        Our merchant energy business also has committed to contribute additional capital for our construction program and to make additional loans to some affiliates, joint ventures, and partnerships in which they have an interest.

        At December 31, 2001, we estimate the future obligations of our merchant energy business in the following table:

 
   2002
   2003
   2004
   2005
   2006
   Thereafter
   Total
 
   (In millions)
Purchased capacity and energy   $ 16.4   $ 16.0   $ 15.5   $ 15.1   $ 15.0   $ 98.5   $ 176.5
Fuel and transportation     318.1     228.3     99.5     49.1     48.8     17.7     761.5
Capital and loans     81.5     0.8     —     —     —     —     82.3
Total future obligations   $ 416.0   $ 245.1   $ 115.0   $ 64.2   $ 63.8   $ 116.2   $ 1,020.3

        Our regulated gas business enters into various long-term contracts for the procurement, transportation, and storage of gas. These contracts are recoverable under BGE's gas cost adjustment clause discussed in Note 1.

        BGE Home Products & Services has gas purchase commitments of $35.0 million in 2002 and $2.2 million in 2003 related to its gas program.


Sale of Receivables

BGE and BGE Home Products & Services have agreements to sell on an ongoing basis an undivided interest in a designated pool of customer receivables. Under the agreements, BGE can sell up to a total of $25 million, and BGE Home Products & Services can sell up to a total of $50 million. Under the terms of the agreements, the buyer of the receivables has limited recourse against these entities. BGE and BGE Home Products & Services have recorded reserves for credit losses. At December 31, 2001, BGE had sold $8.1 million and BGE Home Products & Services had sold $42.5 million of receivables under these agreements.

84


Guarantees

At December 31, 2001, Constellation Energy issued guarantees in an amount up to $1,682.4 million related to credit facilities and contractual performance of certain of its nonregulated subsidiaries, including $600 million relating to the High Desert project. The actual subsidiary liabilities related to these guarantees totaled $369.9 million at December 31, 2001.

        At December 31, 2001, Constellation Nuclear guaranteed the $388.1 million sellers' note that financed the acquisition of Nine Mile Point. This guarantee contains covenant provisions that require Constellation Nuclear to maintain a net worth of at least $500 million and a ratio of current assets to current liabilities of at least 1.1.

        At December 31, 2001, our merchant energy business had other guaranteed outstanding loans and letters of credit of certain power projects totaling $26.7 million.

        At December 31, 2001, our other nonregulated businesses had guaranteed outstanding loans and letters of credit of real estate projects totaling $15.9 million.

        BGE guarantees two-thirds of certain debt of Safe Harbor Water Power Corporation. At December 31, 2001, Safe Harbor Water Power Corporation had outstanding debt of $20 million. The maximum amount of BGE's guarantee is $13.3 million. Additionally at December 31, 2001, BGE guaranteed the TOPrS of $250.0 million as discussed in Note 9.

        We assess the risk of loss from these guarantees to be minimal.


Environmental Matters

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

        The development (involving site selection, environmental assessments, and permitting), construction, acquisition, and operation of electric generating, transmission, and distribution facilities are subject to extensive federal, state, and local environmental and land use laws and regulations. From the beginning phases of siting and developing, to the ongoing operation of existing or new electric generating, transmission, and distribution facilities, our activities involve compliance with diverse laws and regulations that address emissions and impacts to air and water, special, protected, and cultural resources (such as wetlands, endangered species, and archeological/historical resources), chemical and waste handling, and noise impacts.

        Our activities require complex and often lengthy processes to obtain approvals, permits, or licenses for new, existing, or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires preparation of release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or their operation, as required.

        We discuss the significant matters below.

Clean Air Act

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

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

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

        The Ozone Transport Assessment Group, composed of state and local air regulatory officials from the 37 Mid-Western and Eastern states, has recommended additional NOX 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 NOX (a precursor of ozone). Among other things, the EPA's rule establishes an ozone season, which runs from May through September, and a NOX emission budget for each state, including Maryland and Pennsylvania. The EPA rule requires states to

85

implement controls sufficient to meet their NOX budget by May 30, 2004. Coal-fired power plants are a principal target of NOX 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 NOX reduction requirements under the EPA rule including those located in Maryland and Pennsylvania. This regulation affects both new and existing facilities causing additional capital investment. At the Brandon Shores facility we have installed and at our Wagner facility we are installing, emission reduction equipment by May 2002 to meet Maryland regulations issued pursuant to EPA's rule. The owners of the Keystone plant in Pennsylvania are installing emissions reduction equipment by 2003 to meet Pennsylvania regulations issued pursuant to EPA's rule. We estimate that the equipment needed at these plants will cost approximately $290 million. Through December 31, 2001, we have spent approximately $200 million.

        Over the past two years, the EPA and several states have filed suits against a number of coal-fired power plants in Mid-Western and Southern states alleging violations of the deterioration prevention and non-attainment provisions of the Clean Air Act's new source review requirements. In 2000, using its broad investigatory powers, the EPA requested information relating to modifications made to our Brandon Shores, Crane, and Wagner plants in Baltimore, Maryland. The EPA also sent similar, but narrower, information requests to two of our newer Pennsylvania waste-coal burning plants. We have responded to the EPA and are waiting to see if the EPA takes any further action. This information is to determine compliance with the Clean Air Act and state implementation plan requirements, including potential application of federal New Source Performance Standards.

        In general, such standards can require the installation of additional air pollution control equipment upon the major modification of an existing plant. Although there have not been any new source review-related suits filed against our facilities, there can be no assurance that any of them will not be the target of an action in the future. Based on the levels of emissions control that the EPA and/or states are seeking in these new source review enforcement actions, we believe that material additional costs and penalties could be incurred, and/or planned capital expenditures could be accelerated, if the EPA was successful in any future actions regarding our facilities.

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

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

Waste Disposal

The EPA and several state agencies have notified us that we are considered a potentially responsible party with respect to the cleanup of certain environmentally contaminated sites owned and operated by others. We cannot estimate the cleanup costs for all of these sites.

        We can, however, estimate that our current 15.47% share of the reasonably possible cleanup costs at one of these sites, Metal Bank of America, a metal reclaimer in Philadelphia, could be as much as $2.3 million higher than amounts we have recorded as a liability on our Consolidated Balance Sheets. This estimate is based on a Record of Decision issued by the EPA.

        Also, we are coordinating investigation of several sites where gas was manufactured in the past. The investigation of these sites includes reviewing possible actions to remove coal tar. In late December 1996, we signed a consent order with the Maryland Department of the Environment (MDE) that required us to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. We submitted the required remedial action plans and they were approved by the MDE. Based on the remedial action plans, the costs we consider to be probable to remedy the contamination are estimated to total $47 million. We have recorded these costs as a liability on our Consolidated Balance Sheets and have deferred these costs, net of accumulated amortization and amounts we recovered from insurance companies, as a regulatory asset. Because of the results of studies at these sites, it is reasonably possible that these additional costs could exceed the amount we recognized by approximately $14 million. We discuss this further in Note 6. Through December 31, 2001, we have spent approximately $37 million for remediation at this site.

        We do not expect the cleanup costs of the remaining sites to have a material effect on our financial results.


Litigation

In the normal course of business, we are involved in various legal proceedings. We discuss the significant matters below.

California

Baldwin Associates, Inc. v. Gray Davis, Governor of California and 22 other defendants (including Constellation Power Development, Inc., a subsidiary of Constellation Power, Inc.)—This class action lawsuit was filed on October 5, 2001 in the Superior Court, County of San Francisco. The action seeks damages of $43 billion, recession and reformation of approximately 38 long-term power purchase contracts, and an injunction against improper spending by the state of California. Constellation Power Development, Inc. is named as a defendant but does not have a power purchase agreement with the State of California. However, our High Desert Power Project does have a power

86

purchase agreement with the California Department of Water Resources. We believe this case is without merit. However, we cannot predict the timing, or outcome, of it or its possible effect on our financial results.

Employment Discrimination

Miller, et. al v. Baltimore Gas and Electric Company, et al.—This action was filed on September 20, 2000 in the U.S. District Court for the District of Maryland. Besides BGE, Constellation Energy Group, Constellation Nuclear, and Calvert Cliffs Nuclear Power Plant are also named defendants. The action seeks class certification for approximately 150 past and present employees and alleges racial discrimination at Calvert Cliffs Nuclear Power Plant. The amount of damages is unspecified, however the plaintiffs seek back and front pay, along with compensatory and punitive damages. The Court scheduled a briefing process for the motion to certify the case as a class action suit for the beginning of 2003. We believe this case is without merit. However, we cannot predict the timing, or outcome, of it or its possible effect on our, or BGE's, financial results.

Asbestos

Since 1993, BGE has been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that BGE knew of and exposed individuals to an asbestos hazard. The actions relate to two types of claims.

        The first type is direct claims by individuals exposed to asbestos. BGE is involved in these claims with approximately 70 other defendants. Approximately 545 individuals that were never employees of BGE each claim $6 million in damages ($2 million compensatory and $4 million punitive). These claims were filed in the Circuit Court for Baltimore City, Maryland in the summer of 1993. BGE does not know the specific facts necessary to estimate its potential liability for these claims. The specific facts BGE does not know include:

        To date, 36 of these cases were settled for amounts that were not significant.

        The second type is claims by one manufacturer—Pittsburgh Corning Corp. (PCC)—against BGE and approximately eight others, as third-party defendants. On April 17, 2000, PCC declared bankruptcy, and BGE does not expect PCC to prosecute these claims.

        These claims relate to approximately 1,500 individual plaintiffs and were filed in the Circuit Court for Baltimore City, Maryland in the fall of 1993. To date, about 375 cases have been resolved, all without any payment by BGE. BGE does not know the specific facts necessary to estimate its potential liability for these claims. The specific facts we do not know include:

        Until the relevant facts for both types of claims are determined, BGE is unable to estimate what its liability, if any, might be. Although insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions, the potential liability could be material.

Asset Transfer Order

On July 6, 2000, the Mid-Atlantic Power Supply Association (MAPSA) and Shell Energy LLC filed, in the Circuit Court for Baltimore City, a petition for review and a delay of the Maryland PSC's order approving the transfer of BGE's generation assets issued on June 19, 2000. The Court denied MAPSA's request for a delay on August 4, 2000, and after a hearing on the petition on August 23, 2000 issued an order on September 29, 2000 upholding the Maryland PSC's order on the asset transfer. On October 27, 2000, MAPSA filed an appeal with the Maryland Court of Special Appeals challenging the September 29, 2000 order issued by the Circuit Court. The Court of Special Appeals heard oral arguments on the appeal on September 7, 2001. We also believe that this petition is without merit. However, we cannot predict the timing or outcome of this case, which could have a material adverse effect on our, and BGE's, financial results.

Restructuring Order

In early December 1999, MAPSA, Trigen-Baltimore Energy Corporation, and Sweetheart Cup Company, Inc. filed appeals of the Restructuring Order, which were consolidated in the Baltimore City Circuit Court. MAPSA also filed a motion to delay implementation of the Restructuring Order, pending a decision on the merits of the appeals by the court.

        On April 21, 2000, the Circuit Court dismissed MAPSA's appeal based on a lack of standing (the right of a party to bring a lawsuit to court) and denied its motion for a delay of the Restructuring Order. However, MAPSA filed an appeal of this decision. On May 24, 2000, the Circuit Court dismissed both the Trigen and Sweetheart Cup appeals.

        MAPSA subsequently filed several appeals with the Maryland Court of Special Appeals, the Maryland Court of Appeals, and the Baltimore City Circuit Court. The effect of the appeals was to delay the implementation of customer choice in BGE's service territory.

        However, on August 4, 2000, the delay was rescinded and BGE retroactively adjusted its rates as if customer choice had been implemented July 1, 2000.

        On September 29, 2000, the Baltimore City Circuit Court issued an order upholding the Restructuring Order.

        On October 27, 2000, MAPSA filed an appeal with the Maryland Court of Special Appeals challenging the

87

September 29, 2000 order issued by the Circuit Court. The Court of Special Appeals heard oral arguments on the appeal on September 7, 2001. We believe that this petition is without merit. However, we cannot predict the timing or outcome of this case, which could have a material adverse effect on our, and BGE's, financial results.


Nuclear Insurance

We maintain nuclear insurance coverage for Calvert Cliffs and Nine Mile Point in four program areas: liability, worker radiation claims, property, and accidental outage. However, these policies have certain industry standard exclusions, such as ordinary wear and tear and war. Terrorist acts, while not excluded from the property and accidental outage policies, are covered as a common occurrence, meaning that if terrorist acts occur against one or more commercial nuclear power plants insured by our insurance company within a 12-month period, they will be treated as one event and the owners of the plants will share one full limit of each type of policy (currently $3.24 billion). Claims that arise out of terrorist acts are also covered by our nuclear liability and worker radiation policies. However, these policies are subject to one industry aggregate limit (currently $200 million) for the risk of terrorism. Unlike the property and accidental outage policies, however, an industry-wide retrospective assessment program applies above the industry limit (see below for an explanation of this program).

        If there were an accident or an extended outage at any unit of Calvert Cliffs or Nine Mile Point, it could have a substantial adverse financial effect on us.

Liability Insurance

Pursuant to the Price-Anderson Act, we are required to insure against public liability claims resulting from nuclear incidents to the full limit of approximately $9.5 billion. We have purchased the maximum available commercial insurance of $200 million, and the remaining $9.3 billion is provided through mandatory participation in an industry-wide retrospective assessment program. Under this retrospective assessment program, we can be assessed up to $352.4 million per incident, payable at no more than $40 million per incident per year. This assessment also applies in excess of our worker radiation claims insurance and is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose additional revenue-raising measures to pay claims.

        Some of the provisions of this Act expire in August 2002, and the Act is subject to change if those provisions are extended. While we expect these provisions to be extended, we do not know what impact any changes to the Act may have on us.

Worker Radiation Claims Insurance

We participate in the American Nuclear Insurers Master Worker Program that provides coverage for worker tort claims filed for radiation injuries. Effective January 1, 1998, this program was modified to provide coverage to all workers whose nuclear-related employment began on or after the commencement date of reactor operations. Waiving the right to make additional claims under the old policy was a condition for acceptance under the new policy. We describe the old and new policies below:

        The sellers of Nine Mile Point retain the liabilities for existing and potential claims that occurred prior to November 7, 2001. In addition, the Long Island Power Authority, which continues to own 18 percent of Unit 2 at Nine Mile Point, is obligated to assume its pro rata share of any liabilities for retrospective premiums and other premiums assessments. If claims under these policies exceed the coverage limits, the provisions of the Price-Anderson Act would apply.

Property Insurance

Our policies provide $500 million in primary and an additional $2.25 billion in excess coverage for property damage, decontamination, and premature decommissioning liability for Calvert Cliffs or Nine Mile Point. If accidents at any insured plants cause a shortfall of funds at the industry mutual insurance company, all policyholders could be assessed, with our share being up to $56.2 million.

Accidental Outage Insurance

Our policies provide indemnification on a weekly basis resulting from an accidental outage of a nuclear unit. Initial coverage begins after a 12-week deductible period and continues at 100% of the weekly indemnity limit for 52 weeks and 80% of the weekly indemnity limit for the next 110 weeks. Our coverage is up to $490.0 million per unit at Calvert Cliffs, $335.4 million for Unit 1 of Nine Mile Point, and $412.6 million for Unit 2 of Nine Mile Point. This amount can be reduced by up to $98.0 million per unit at Calvert Cliffs and $82.5 million for Nine Mile Point if an outage at either plant is caused by a single insured physical damage loss.


California Power Purchase Agreements

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

88

approximately $45 million. We recorded reserves of approximately 20% of this amount.

        These projects entered into agreements with PGE and SCE that provide for five-year fixed-price payments averaging $53.70 per megawatt-hour plus the stated capacity payments in the original Interim Standard Offer No. 4 (SO4) contracts. These agreements also provide for the payment of all past due amounts plus interest, which the projects expect to collect within the next two years. The SCE agreement to pay these past due amounts is contingent on SCE making certain payments to other creditors.

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

12 Risk Management Activities and Fair Value of Financial Instruments

Risk Management Activities

In 2001, we entered into forward starting interest rate swap contracts to manage a portion of our interest rate exposure for anticipated long-term borrowings to refinance our outstanding commercial paper obligations and maturing long-term debt. The swaps have notional or contract amounts that total $800 million with an average rate of 4.9% and expire in the first quarter of 2002. The notional amounts of the contracts do not represent amounts that are exchanged by the parties and are not a measure of our exposure to market or credit risks. The notional amounts are used in the determination of the cash settlements under the contracts. At December 31, 2001, the fair value of these swaps was an unrealized pre-tax gain of $36.3 million.

        At December 31, 2001, these swaps were designated as cash-flow hedges under SFAS No. 133. We recorded this unrealized gain in "Other current assets" in our Consolidated Balance Sheets and "Accumulated other comprehensive income," net of associated deferred income tax effects, in our Consolidated Statements of Common Shareholders' Equity and Consolidated Statements of Capitalization. Any gain or loss on the hedges will be reclassified from "Accumulated other comprehensive income" into "Interest expense" and be included in earnings during the periods in which the interest payments being hedged occur.

        In 2002, we entered into additional forward starting interest rate swaps with notional amounts that total $700 million. These swaps have an average rate of 5.9% and expire in the first quarter of 2002.

        Our power marketing operation manages the commodity price risk of our electric generation operations as part of its overall portfolio. In order to manage this risk, our merchant energy business may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of electricity and purchases of fuel as discussed in Note 1.

        At December 31, 2001, our merchant energy business had designated certain fixed-price forward electricity sale contracts as cash-flow hedges of forecasted sales of electricity for the years 2002 through 2010 under SFAS No. 133.

        At December 31, 2001, our merchant energy business recorded net unrealized pre-tax gains of $76.5 million on these hedges, net of associated deferred income tax effects, in "Accumulated other comprehensive income." We expect to reclassify $5.7 million of net pre-tax gains on cash-flow hedges from "Accumulated other comprehensive income" into earnings during the next twelve months based on the market prices at December 31, 2001. However, the actual amount reclassified into earnings could vary from the amounts recorded at December 31, 2001 due to future changes in market prices. In 2001, there was no hedge ineffectiveness recognized in earnings.

        At December 31, 2000, our merchant energy business recorded deferred pre-tax hedge losses of $58.3 million in "Other deferred charges" in our Consolidated Balance Sheets for the fixed-price forward electricity sale contracts designated as a hedge of forecasted sales of electricity. We reclassified these deferred hedge losses, net of associated deferred income tax effects, to "Accumulated other comprehensive income" upon the adoption of SFAS No. 133, in the first quarter of 2001.


Fair Value of Financial Instruments

The fair value of a financial instrument represents the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Significant differences can occur between the fair value and carrying amount of financial instruments that are recorded at historical amounts. We use the following methods and assumptions for estimating fair value disclosures for financial instruments:

89

        We show the carrying amounts and fair values of financial instruments included in our Consolidated Balance Sheets in the following table, and we describe some of the items separately later in this section.

At December 31,

   2001

   2000
 
   Carrying Amount
   Fair Value
   Carrying Amount
   Fair Value
 
   (In millions)
Investments and other assets for which it is:                        
  Practicable to estimate fair value   $ 1,144.9   $ 1,144.9   $ 349.8   $ 349.8
  Not practicable to estimate fair value     25.8     N/A     32.7     N/A
Fixed-rate long-term debt     2,945.3     3,069.6     2,734.1     2,819.9
Variable-rate long-term debt     1,179.1     1,179.1     1,331.8     1,331.8

        It was not practicable to estimate the fair value of investments held by our nonregulated businesses in several financial partnerships that invest in nonpublic debt and equity securities. This is because the timing and amount of cash flows from these investments are difficult to predict. We report these investments at their original cost in our Consolidated Balance Sheets.

        The investments in financial partnerships totaled $25.8 million at December 31, 2001 and $32.7 million at December 31, 2000, representing ownership interests up to 11%. The total assets of all of these partnerships totaled $5.4 billion at December 31, 2000 (which is the latest information available).

Guarantees

It was not practicable to determine the fair value of certain loan guarantees of Constellation Energy and its subsidiaries. Constellation Energy guaranteed outstanding debt of $47.9 million at December 31, 2001 and $341.0 million at December 31, 2000.

        Our merchant energy business guaranteed outstanding debt totaling $414.8 million at December 31, 2001 and $33.6 million at December 31, 2000.

        Our other nonregulated businesses guaranteed outstanding debt totaling $15.9 million at December 31, 2001 and $16.5 million at December 31, 2000.

        BGE guaranteed outstanding debt of $263.3 million at December 31, 2001 and 2000.

        We do not anticipate that we will need to fund these guarantees.

13 Stock-Based Compensation

As permitted by SFAS No. 123, Accounting for Stock-Based Compensation, we measure our stock-based compensation in accordance with Accounting Principles Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, and related interpretations.

        Under our existing long-term incentive plans, we can issue awards that include stock options and performance-based restricted stock to officers and key employees. Under the plans, we can issue up to a total of 6,000,000 shares for these awards.


Stock Options

In May 2000, our Board of Directors approved the issuance of nonqualified stock options. Options have been granted at prices not less than the market value of the stock at the date of grant, generally become exercisable ratably over a three-year period beginning one year from the date of grant, and expire ten years from the date of grant. In accordance with APB No. 25, no compensation expense is recognized for the stock option awards. Summarized information for our stock option awards is as follows:

 
   2001

   2000

  
 
   Shares
   Weighted-
Average Exercise Price
   Shares
   Weighted-
Average Exercise Price
  
 
 
   (In thousands, except per share amounts)

  
Outstanding, beginning of year   2,420   $ 34.65   —   $ —  
  Granted   1,015     25.08   2,462     34.64  
  Exercised   (512 )   (34.25 ) —     —  
  Cancelled/ Expired   (277 )   (37.74 ) (42 )   (34.25 )
 
Outstanding, end of year   2,646   $ 30.73   2,420   $ 34.65  
 
Exercisable, end of year   235   $ 34.25   —     —  
 
Weighted-average fair value per share of options granted       $ 9.27       $ 5.60  
 

90

        The following table summarizes information about stock options outstanding at December 31, 2001 (shares in thousands):

Plan Year
   Exercise Prices
   Number Outstanding
   Weighted-Average Remaining Contractual Life
   Number Exercisable
2001   $ 25.08   1,015   9.9   —
2000   $ 34.25   1,631   8.4   235


Performance-Based Restricted Stock Awards

In addition, we issue common stock based on meeting certain performance and service goals over a three to five year period. This stock vests to participants at various times ranging from three to five years or less. In accordance with APB No. 25, we recognize compensation expense for our restricted stock awards using the variable accounting method. In 2001, due to non-attainment of performance criteria, we recorded a credit to compensation expense of $10.1 million. We recorded compensation expense of $16.3 million for 2000 and $10.5 million for 1999. Summarized share information for our restricted stock awards is as follows:

 
   2001
   2000
   1999
  
 
 
   (In thousands, except per share amounts)

  
Outstanding, beginning of year     377     323     350  
  Granted     87     353     358  
  Released to participants     —     (277 )   (362 )
  Cancelled     (29 )   (22 )   (23 )
 
Available for grant, end of year     435     377     323  
 
Weighted-average fair value restricted stock granted   $ 35.24   $ 32.89   $ 28.61  
 


Pro-forma Information

Disclosure of pro-forma information regarding net income and earnings per share is required under SFAS No. 123, which uses the fair value method. The fair values of our stock-based awards were estimated as of the date of grant using the Black-Scholes option pricing model based on the following weighted-average assumptions:

 
   2001
   2000
    
  
 
Risk-free interest rate   4.79 % 6.37 %    
Expected life (in years)   5.0   10.0      
Expected market price volatility factors   41.3 % 21.0 %    
Expected dividend yields   1.8 % 5.7 %    

        Had compensation cost for these plans been recognized under the fair value method, net income and basic and diluted earnings per share amounts would have been as follows:

 
   2001
(In millions, except per share amounts)
Pro-forma net income   $ 87.2
Pro-forma earnings per share:      
  Basic   $ .54
  Diluted   $ .54

        The effect of applying SFAS No. 123 to our stock-based awards results in net income and earnings per share that are not materially different from amounts reported for the year ended December 31, 2000.

14 Acquisition of Nine Mile Point

On November 7, 2001, we completed our purchase of Nine Mile Point located in Scriba, New York. Nine Mile Point consists of two boiling-water reactors. Unit 1 is a 609-megawatt reactor that entered service in 1969. Unit 2 is a 1,148-megawatt reactor that began operation in 1988.

        Nine Mile Point Nuclear Station, LLC, a subsidiary of Constellation Nuclear, purchased 100 percent of Nine Mile Point Unit 1 and 82 percent of Unit 2. Approximately one-half of the purchase price, or $380 million, in addition to settlement costs of $2.7 million, was paid at closing. The remainder is being financed through the sellers in a note to be repaid over five years with an interest rate of 11.0%. This note may be prepaid at any time without penalty. The sellers also transferred to us approximately $442 million in decommissioning funds. As a result of this purchase, we own 1,550 megawatts of Nine Mile Point's 1,757 megawatts of total generating capacity.

        Niagara Mohawk Power Corporation was the sole owner of Nine Mile Point Unit 1. The co-owners of Unit 2 who sold their interests are: Niagara Mohawk (41 percent), New York State Electric and Gas (18 percent), Rochester Gas & Electric Corporation (14 percent), and Central Hudson Gas & Electric Corporation (9 percent). The Long Island Power Authority will continue to own 18 percent of Unit 2.

        We will sell 90 percent of our share of Nine Mile Point's output back to the sellers at an average price of nearly $35 per megawatt-hour for approximately 10 years under power purchase agreements. The contracts for the output are on a unit contingent basis (if the output is not available because the plant

91

is not operating, there is no requirement to provide output from other sources).


Nine Mile Point Net Assets Acquired

At November 7, 2001

    
 
   (In millions)
Current Assets   $ 135.4
Nuclear Decommissioning Trust Fund     441.7
Net Property, Plant and Equipment     292.6
Intangible Assets (details below)     38.7
Total Assets Acquired     908.4

Current Liabilities
 
 
16.9
Deferred Credits and Other Liabilities     120.7
Net Assets Acquired     770.8
Note to Sellers     388.1
Total cash paid   $ 382.7

        The intangible assets acquired consist of the following:

Description
  Amount
   Weighted-
Average Useful Life
 
   (In millions)

   (In years)
Operating procedures and manuals   $ 23.4   10
Permits and licenses     12.9   27
Software     2.4   5
   
Total intangible assets   $ 38.7    
   

        In 2002, Niagara Mohawk, or its successor, will provide funds equal to the net pension obligation of Nine Mile Point employees following a more precise estimate of this obligation. Refer to Note 7 for additional information.

15 Related Party Transactions—BGE

Income Statement

Under the Restructuring Order, BGE is providing standard offer service to customers at fixed rates over various time periods during the transition period, July 1, 2000 to June 30, 2006, for those customers that do not choose an alternate supplier. Constellation Power Source is under contract to provide BGE with the energy and capacity required to meet its standard offer service obligations for the first three years of the transition period, and 90% of the energy and capacity for the final three years (July 1, 2003—June 30, 2006) of the transition period. The cost of BGE's purchased energy from nonregulated affiliates of Constellation Energy to meet its standard offer service obligation was $1,150.1 million and $581.0 million for the years ended December 31, 2001 and 2000, respectively.

        In addition, BGE receives charges from Constellation Energy for certain corporate functions. Certain costs are directly assigned to BGE. We allocate other corporate function costs based on a total percentage of expected use by BGE. Management believes this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity. These costs were $18.8 million and $21.6 million for the years ended December 31, 2001 and 2000, respectively.


Balance Sheet

As a result of the deregulation of electric generation, BGE transferred its generation assets to nonregulated affiliates of Constellation Energy effective July 1, 2000. In conjunction with this transfer, Constellation Power Source Generation, Inc. issued approximately $366 million in unsecured promissory notes to BGE. All of these notes have been repaid by Constellation Power Source Generation, Inc. The proceeds were used to service current maturities of certain BGE long-term debt.

        BGE participates in a cash pool under a Master Demand Note agreement with Constellation Energy. Under this arrangement, participating subsidiaries may invest in or borrow from the pool at market interest rates. Constellation Energy administers the pool and invests excess cash in short-term investments. Under this arrangement, BGE had invested $439.1 million at December 31, 2001 and was neither borrowed nor invested at December 31, 2000.

        Amounts related to corporate functions performed at the Constellation Energy holding company, BGE's purchases to meet its standard offer service obligation, and BGE's charges to Constellation Energy and its nonregulated affiliates for certain services it provides them result in intercompany balances on BGE's Consolidated Balance Sheets.

        Management believes its allocation methods are reasonable and approximate the costs that would be charged to unaffiliated entities.

92

16 Quarterly Financial Data (Unaudited)

Our quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair presentation. Our utility business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.


2001 Quarterly Data—Constellation Energy

 
   Revenue
   Income from Operations
   Earnings Applicable to Common Stock
   Earnings Per Share of Common Stock
  
 
 
   (In millions, except per-share amounts)

  
Quarter Ended                          
  March 31   $ 1,147.1   $ 235.0   $ 111.8   $ 0.74  
  June 30     843.2     171.0     75.6     0.46  
  September 30     1,036.1     317.5     163.6     1.00  
  December 31     901.9     (365.7 )   (260.1 )   (1.59 )
 
Year Ended                          
  December 31   $ 3,928.3   $ 357.8   $ 90.9   $ 0.57  
 


2001 Quarterly Data—BGE

 
   Revenue
   Income from Operations
   Earnings Applicable to Common Stock
  
 
 
   (In millions)

  
Quarter Ended                    
  March 31   $ 849.9   $ 141.1   $ 55.1  
  June 30     607.2     75.0     19.9  
  September 30     701.3     80.3     23.8  
  December 31     562.3     15.4     (14.7 )
 
Year Ended                    
  December 31   $ 2,720.7   $ 311.8   $ 84.1  
 

First quarter results include:

Constellation Energy

Fourth quarter results include:

Constellation Energy and BGE

Constellation Energy


2000 Quarterly Data—Constellation Energy

 
   Revenue
   Income from Operations
   Earnings Applicable to Common Stock
   Earnings Per Share of Common Stock
 
   (In millions, except per-share amounts)
Quarter Ended                        
  March 31   $ 994.0   $ 184.6   $ 72.1   $ 0.48
  June 30     866.6     132.1     39.6     0.26
  September 30     968.6     313.4     147.5     0.98
  December 31     1,023.3     212.5     86.1     0.57
Year Ended                        
  December 31   $ 3,852.5   $ 842.6   $ 345.3   $ 2.30


2000 Quarterly Data—BGE

 
   Revenue
   Income from Operations
   Earnings Applicable to Common Stock
 
   (In millions)
Quarter Ended                  
  March 31   $ 719.7   $ 134.0   $ 50.9
  June 30     658.1     127.0     49.1
  September 30     688.5     65.2     10.0
  December 31     680.5     86.2     20.3
Year Ended                  
  December 31   $ 2,746.8   $ 412.4   $ 130.3

First quarter results include:

Constellation Energy and BGE

Second quarter results include:

Constellation Energy and BGE

Constellation Energy

The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and dilution as a result of issuing common shares during the year.

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

93


Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.


PART III

BGE meets the conditions set forth in General Instruction I(1)(a)and (b) of Form 10-K for a reduced disclosure format. Accordingly, all items in this section related to BGE are not presented.


Item 10. Directors and Executive Officers of the Registrant

The information required by this item with respect to directors is set forth under Election of Constellation Energy Directors in the Proxy Statement and is incorporated herein by reference.

        The information required by this item with respect to executive officers of Constellation Energy Group, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, is set forth in Item 4 of Part I of this Form 10-K under Executive Officers of the Registrant.

        The information required by this item with respect to compliance with Section 16(a) of the Securities Exchange Act of 1934 is set forth under Section 16(a) Beneficial Ownership Reporting Compliance in the proxy statement and is incorporated herein by reference.


Item 11. Executive Compensation

The information required by this item is set forth under Directors' Compensation, Compensation Committee Interlocks and Insider Participation, Executive Compensation, Common Stock Performance Graph and Report of Committee on Management on Executive Compensation in the Proxy Statement and is incorporated herein by reference.


Item 12. Security Ownership of Certain Beneficial Owners and Management

The information required by this item is set forth under Security Ownership in the Proxy Statement and is incorporated herein by reference.


Item 13. Certain Relationships and Related Transactions

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

        The additional information required by this item is set forth under Certain Relationships and Transactions and Compensation Committee Interlocks and Insider Participation in the Proxy Statement and is incorporated herein by reference.

94


PART IV

Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K

    (a) The following documents are filed as a part of this Report:
1.   Financial Statements:
    Report of Independent Accountants dated January 21, 2002 of PricewaterhouseCoopers LLP
    Consolidated Statements of Income—Constellation Energy Group for three years ended December 31, 2001
    Consolidated Statements of Comprehensive Income—Constellation Energy Group for three years ended December 31, 2001
    Consolidated Balance Sheets—Constellation Energy Group at December 31, 2001 and December 31, 2000
    Consolidated Statements of Cash Flows—Constellation Energy Group for three years ended December 31, 2001
    Consolidated Statements of Common Shareholders' Equity—Constellation Energy Group for three years ended December 31, 2001
    Consolidated Statements of Capitalization—Constellation Energy Group at December 31, 2001 and December 31, 2000
    Consolidated Statements of Income Taxes—Constellation Energy Group for three years ended December 31, 2001
    Consolidated Statements of Income—Baltimore Gas and Electric Company for three years ended December 31, 2001
    Consolidated Statements of Comprehensive Income—Baltimore Gas and Electric Company for three years ended December 31, 2001
    Consolidated Balance Sheets—Baltimore Gas and Electric Company at December 31, 2001 and December 31, 2000
    Consolidated Statements of Cash Flows—Baltimore Gas and Electric Company for three years ended December 31, 2001
    Notes to Consolidated Financial Statements
2.   Financial Statement Schedules:
    Schedule II—Valuation and Qualifying Accounts
    Schedules other than Schedule II are omitted as not applicable or not required.
3.   Exhibits Required by Item 601 of Regulation S-K.

Exhibit Number
 
 
 
 
*2   —   Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 in Form S-4 dated March 3, 1999, File No. 33-64799.)
*2 (a) —   Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)
*2 (b) —   Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)
*3 (a) —   Articles of Amendment and Restatement of the Charter of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Exhibit No. 99.2 in Form 8-K dated April 30, 1999, File No. 1-1910.)
*3 (b) —   Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999. (Designated as Exhibit No. 3(a) in Form 10-Q dated August 13, 1999, File Nos. 1-12869 and 1-1910.)
*3 (c) —   Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999. (Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)
*3 (d) —   Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 in Form 10-Q dated November 14, 1996, File No. 1-1910.)
3 (e) —   Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 20, 2001.
3 (f) —   Bylaws of Constellation Energy Group, Inc, as amended to February 25, 2002.

95

*3 (g) —   Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 in Form 10-Q dated November 13, 1998, File No. 1-1910.)
*4 (a) —   Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) in Form S-3 dated March 29,1999, File No. 333-75217.)
*4 (b) —   Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910); and the following Supplemental Indentures between BGE and Bankers Trust Company, Trustee:

Dated
 
File No.
 
Designated In
 
Exhibit Number
*July 15, 1977   2-59772       2-3
(3 Indentures)            
*August 15, 1991   33-45259   (Form S-3 Registration)   4(a)(i)
*January 15, 1992   33-45259   (Form S-3 Registration)   4(a)(ii)
*July 1, 1992   1-1910   (Form 8-K Report for January 29, 1993)   4(a)
*February 15, 1993   1-1910   (Form 10-K Annual Report for 1992)   4(a)(i)
*March 1, 1993   1-1910   (Form 10-K Annual Report for 1992)   4(a)(ii)
*March 15, 1993   1-1910   (Form 10-K Annual Report for 1992)   4(a)(iii)
*April 15, 1993   1-1910   (Form 10-Q dated May 13, 1993)   4
*July 1, 1993   1-1910   (Form 10-Q dated August 13, 1993)   4(a)
*October 15, 1993   1-1910   (Form 10-Q dated November 12, 1993)   4
*June 15, 1996   1-1910   (Form 10-Q dated August 13, 1996)   4

*4
(c)
—
 
Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
*4 (d) —   Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures. (Designated as Exhibit 4(d) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4 (e) —   Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures. (Designated as Exhibit 4(e) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4 (f) —   Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4 (g) —   Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4 (h) —   Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4 (i)  —   Specimen Note for $173,000,000 6.75% Remarketable or Redeemable Securities (ROARSSM) due 2012 (Designated as Exhibit 4(f) in Form 8-K dated December 20, 2000, File No. 1-1910.)
10 (a) —   Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated.
*10 (b) —   Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 2000, File Nos. 1-12869 and 1-1910.)
10 (c) —   Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated.

96

10 (d) —   Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated.
*10 (e) —   Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(m) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
*10 (f) —   Summary of severance arrangement for Edward A. Crooke. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)
*10 (g) —   Grantor Trust Agreement Dated as of January 1, 2001 between Constellation Energy Group, Inc. and Citibank, N.A. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 2000, File Nos. 1-12869 and 1-1910.)
10 (h) —   Form of Severance Agreements between Constellation Energy Group, Inc. and the following named executive officers: Christian H. Poindexter, Mayo A. Shattuck, and Frank O. Heintz.
*10 (i) —   Grantor Trust Agreement dated as of April 30, 1999 between Constellation Energy Group, Inc. and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(e) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
*10 (j) —   Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 10-Q dated August 14, 2000, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
*10 (k) —   Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 10-Q dated September 30, 2001, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
*10 (l) —   Full Requirements Service Agreement between Baltimore Gas and Electric Company and Allegheny Energy Supply Company, L.L.C. (Designated as Exhibit No. 10(b) in Form 10-Q dated September 30, 2001, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
10 (m) —   Constellation Energy Group, Inc. Benefits Restoration Plan, as amended and restated.
10 (n) —   Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated.
10 (o) —   Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated.
10 (p) —   Constellation Energy Group, Inc. Supplemental Benefits Plan, as amended and restated.
10 (q) —   Compensation agreements between Constellation Energy Group, Inc. and Michael J. Wallace (Attachment 1—Employment Agreement; Attachment 2—Severance Agreement.)
10 (r) —   Compensation agreements between Constellation Energy Group, Inc. and Thomas V. Brooks (Attachment 1—Offer letter; Attachment 2—Equity letter; Attachment 3—Retention plan summary.)
10 (s) —   Agreement, Release, and Waiver between Constellation Energy Group, Inc. and Eric P. Grubman.
12 (a) —   Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.
12 (b) —   Baltimore Gas and Electric Company and Subsidiaries Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.
21   —   Subsidiaries of the Registrant.
23   —   Consent of PricewaterhouseCoopers LLP, Independent Accountants.

        * Incorporated by Reference.


Date Filed
   Item Reported
Constellation Energy and BGE    
  October 26, 2001   Item 5. Other Event
Item 7. Financial Statements and Exhibits

97


CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
AND
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

Column A
   Column B
   Column C
   Column D
   Column E
  
 
    
   Additions
    
    
  
Description
   Balance at beginning of period
   Charged to costs and expenses
   Charged to Other Accounts—Describe
   (Deductions)—Describe
   Balance at end of period
  
 
   (in millions)

  
Reserves deducted in the Balance Sheet from the assets to which they apply:                                

Constellation Energy
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Accumulated Provision for Uncollectibles                                
    2001   $ 21.3   $ 26.5   $ —   $ (25.0 )(A) $ 22.8  
    2000     34.8     21.1     —     (34.6 )(A)   21.3  
    1999     35.4     21.5     —     (22.1 )(A)   34.8  
  Valuation Allowance—                                
    Net unrealized (gain) loss on available for sale securities                                
    2001     (33.7 )   —     (210.0 )(B)   —     (243.7 )
    2000     0.2     —     (33.9 )(B)   —     (33.7 )
    1999     (9.4 )   —     9.6  (B)   —     0.2  
    Net unrealized (gain) loss on nuclear decommissioning trust funds                                
    2001     (34.7 )   —     13.7  (B)   —     (21.0 )
    2000     (40.5 )   —     5.8  (B)   —     (34.7 )
    1999     (23.9 )   —     (16.6 )(B)   —     (40.5 )
    Mark-to-market energy assets reserves                                
    2001     (54.4 )   —     11.0  (D)   —     (43.4 )
    2000     (27.5 )   —     (26.9 )(D)   —     (54.4 )
    1999     (0.6 )   —     (26.9 )(D)   —     (27.5 )

BGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Accumulated Provision for Uncollectibles                                
    2001     13.4     21.8     —     (21.8 )(A)   13.4  
    2000     13.0     16.4     —     (16.0 )(A)   13.4  
    1999     35.4     17.6     —     (40.0 )(E)   13.0  
  Valuation Allowance—                                
    Net unrealized (gain) loss on available for sale securities                                
    2001     —     —     —     —     —  
    2000     —     —     —     —     —  
    1999     (9.4 )   —     (5.3 )(B)   14.7  (F)   —  
    Net unrealized (gain) loss on nuclear decommissioning trust fund                                
    2001     —     —     —     —     —  
    2000     (40.5 )   —     (1.8 )(C)   42.3  (G)   —  
    1999     (23.9 )   —     (16.6 )(C)   —     (40.5 )
(A)
Represents principally net amounts charged off as uncollectible.
(B)
Represents net unrealized (gains)/losses (credited)/charged to accumulated other comprehensive income.
(C)
Represents net unrealized gains credited to accumulated depreciation.
(D)
Represents reserves from mark-to-market energy assets credited/(charged) to revenues.
(E)
Represents approximately $17 million charged off as uncollectible and approximately $23 million transferred from BGE to Constellation Energy as a result of the formation of the holding company.
(F)
Represents amount transferred from BGE to Constellation Energy as a result of the formation of the holding company.
(G)
Represents balance transferred to a subsidiary of Constellation Nuclear, LLC on July 1, 2000.

98


SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Constellation Energy Group, Inc., the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

      CONSTELLATION ENERGY GROUP, INC.
 (Registrant)		  
 
Date: March 29, 2002
 
By
/s/
MAYO A. SHATTUCK III
 
     
Mayo A. Shattuck III
Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Constellation Energy Group, Inc., the Registrant, and in the capacities and on the dates indicated.

Signature
   Title
   Date

 
 
 
 
 
 
 
Principal executive officer and director:        

By
/s/
M. A. Shattuck III
 
Chief Executive Officer, President and Director
 
March 29, 2002
 
M. A. Shattuck, III

    
    

Principal financial and accounting officer:
 
 

By
/s/
E. F. Smith
 
Senior Vice President and Chief Financial Officer
 
March 29, 2002
 
E. F. Smith

    
    

Directors:
 
 
 
 

/s/
D. L. Becker
 
Director
 
March 29, 2002
D. L. Becker
    
    

/s/
J. T. Brady
 
Director
 
March 29, 2002
J. T. Brady
    
    

/s/
F. P. Bramble, Sr.
 
Director
 
March 29, 2002
F. P. Bramble, Sr.
    
    

/s/
B. B. Byron
 
Director
 
March 29, 2002
B. B. Byron
    
    

/s/
E. A. Crooke
 
Director
 
March 29, 2002
E. A. Crooke
    
    

/s/
J. R. Curtiss
 
Director
 
March 29, 2002
J. R. Curtiss
    
    

/s/
R. W. Gale
 
Director
 
March 29, 2002
R. W. Gale
    
    

99


/s/
F. A. Hrabowski, III
 
Director
 
March 29, 2002
F. A. Hrabowski, III
    
    

/s/
E. J. Kelly, III
 
Director
 
March 29, 2002
E. J. Kelly, III
    
    

/s/
N. Lampton
 
Director
 
March 29, 2002
N. Lampton
    
    

/s/
C. R. Larson
 
Director
 
March 29, 2002
C. R. Larson
    
    

/s/
R. J. Lawless
 
Director
 
March 29, 2002
R. J. Lawless
    
    

/s/
C. H. Poindexter
 
Director
 
March 29, 2002
C. H. Poindexter
    
    

/s/
M. D. Sullivan
 
Director
 
March 29, 2002
M. D. Sullivan
    
    

100

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

    BALTIMORE GAS AND ELECTRIC COMPANY
 (Registrant)		  
 
Date: March 29, 2002
 
By
/s/
FRANK O. HEINTZ
 
     
Frank O. Heintz
President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company, the Registrant, and in the capacities and on the dates indicated.

Signature
   Title
   Date

 
 
 
 
 
 
 
Principal executive officer and director:        

By
/s/
F. O. Heintz
 
President, Chief Executive Officer, and Director
 
March 29, 2002
 
F. O. Heintz

    
    

Principal financial and accounting officer:
 
 
 
 

By
/s/
E. F. Smith
 
Senior Vice President and Chief Financial Officer
 
March 29, 2002
 
E. F. Smith

    
    

Directors:
 
 
 
 

/s/
T. F. Brady
 
Director
 
March 29, 2002
T. F. Brady
    
    

/s/
D. A. Brune
 
Director
 
March 29, 2002
D. A. Brune
    
    

/s/
C. H. Poindexter
 
Director
 
March 29, 2002
C. H. Poindexter
    
    

/s/
M. A. Shattuck, III
 
Director
 
March 29, 2002
M. A. Shattuck, III
    
    

101


EXHIBIT INDEX


Exhibit Number
 
 
 
 
*2   —   Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 in Form S-4 dated March 3, 1999, File No. 33-64799.)
*2 (a) —   Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)
*2 (b) —   Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)
*3 (a) —   Articles of Amendment and Restatement of the Charter of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Exhibit No. 99.2 in Form 8-K dated April 30, 1999, File No. 1-1910.)
*3 (b) —   Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999. (Designated as Exhibit No. 3(a) in Form 10-Q dated August 13, 1999, File Nos. 1-12869 and 1-1910.)
*3 (c) —   Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999. (Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)
*3 (d) —   Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 in Form 10-Q dated November 14, 1996, File No. 1-1910.)
3 (e) —   Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 20, 2001.
3 (f) —   Bylaws of Constellation Energy Group, Inc, as amended to February 25, 2002.
*3 (g) —   Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 in Form 10-Q dated November 13, 1998, File No. 1-1910.)
*4 (a) —   Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) in Form S-3 dated March 29,1999, File No. 333-75217.)
*4 (b) —   Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910); and the following Supplemental Indentures between BGE and Bankers Trust Company, Trustee:

Dated
 
File No.
 
Designated In
 
Exhibit Number
*July 15, 1977   2-59772       2-3
(3 Indentures)            
*August 15, 1991   33-45259   (Form S-3 Registration)   4(a)(i)
*January 15, 1992   33-45259   (Form S-3 Registration)   4(a)(ii)
*July 1, 1992   1-1910   (Form 8-K Report for January 29, 1993)   4(a)
*February 15, 1993   1-1910   (Form 10-K Annual Report for 1992)   4(a)(i)
*March 1, 1993   1-1910   (Form 10-K Annual Report for 1992)   4(a)(ii)
*March 15, 1993   1-1910   (Form 10-K Annual Report for 1992)   4(a)(iii)
*April 15, 1993   1-1910   (Form 10-Q dated May 13, 1993)   4
*July 1, 1993   1-1910   (Form 10-Q dated August 13, 1993)   4(a)
*October 15, 1993   1-1910   (Form 10-Q dated November 12, 1993)   4
*June 15, 1996   1-1910   (Form 10-Q dated August 13, 1996)   4

*4
(c)
—
 
Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)

102

*4 (d) —   Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures. (Designated as Exhibit 4(d) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4 (e) —   Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures. (Designated as Exhibit 4(e) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4 (f) —   Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4 (g) —   Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4 (h) —   Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) in Form S-3 dated May 28, 1998, File No. 333-53767.)
*4 (i)  —   Specimen Note for $173,000,000 6.75% Remarketable or Redeemable Securities (ROARSSM) due 2012 (Designated as Exhibit 4(f) in Form 8-K dated December 20, 2000, File No. 1-1910.)
10 (a) —   Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated.
*10 (b) —   Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 2000, File Nos. 1-12869 and 1-1910.)
10 (c) —   Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated.
10 (d) —   Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated.
*10 (e) —   Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(m) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
*10 (f) —   Summary of severance arrangement for Edward A. Crooke. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)
*10 (g) —   Grantor Trust Agreement Dated as of January 1, 2001 between Constellation Energy Group, Inc. and Citibank, N.A. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 2000, File Nos. 1-12869 and 1-1910.)
10 (h) —   Form of Severance Agreements between Constellation Energy Group, Inc. and the following named executive officers: Christian H. Poindexter, Mayo A. Shattuck, and Frank O. Heintz.
*10 (i) —   Grantor Trust Agreement dated as of April 30, 1999 between Constellation Energy Group, Inc. and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(e) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
*10 (j) —   Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 10-Q dated August 14, 2000, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
*10 (k) —   Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 10-Q dated September 30, 2001, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
*10 (l) —   Full Requirements Service Agreement between Baltimore Gas and Electric Company and Allegheny Energy Supply Company, L.L.C. (Designated as Exhibit No. 10(b) in Form 10-Q dated September 30, 2001, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
10 (m) —   Constellation Energy Group, Inc. Benefits Restoration Plan, as amended and restated.
10 (n) —   Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated.
10 (o) —   Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated.

103

10 (p) —   Constellation Energy Group, Inc. Supplemental Benefits Plan, as amended and restated.
10 (q) —   Compensation agreements between Constellation Energy Group, Inc. and Michael J. Wallace (Attachment 1—Employment Agreement; Attachment 2—Severance Agreement.)
10 (r) —   Compensation agreements between Constellation Energy Group, Inc. and Thomas V. Brooks (Attachment 1—Offer letter; Attachment 2—Equity letter; Attachment 3—Retention plan summary.)
10 (s) —   Agreement, Release, and Waiver between Constellation Energy Group, Inc. and Eric P. Grubman.
12 (a) —   Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.
12 (b) —   Baltimore Gas and Electric Company and Subsidiaries Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.
21   —   Subsidiaries of the Registrant.
23   —   Consent of PricewaterhouseCoopers LLP, Independent Accountants.

        * Incorporated by Reference.

104