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

FORM 10-K


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

For the fiscal year ended DECEMBER 31, 2003

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)

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

410-783-2800

(Registrants' telephone number, including area code)

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

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.

6.20% Trust Preferred Securities ($25 liquidation amount per preferred security) issued by BGE Capital Trust II, 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 ý        No o.

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

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

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

         Aggregate market value of Constellation Energy Group, Inc. Common Stock, without par value, held by non-affiliates as of June 30, 2003 was approximately $5,698,266,202 based upon New York Stock Exchange composite transaction closing price.

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

DOCUMENTS INCORPORATED BY REFERENCE

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 21, 2004.

         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
            Baltimore Gas and Electric Company
            Other Nonregulated Businesses
            Consolidated Capital Requirements
            Environmental Matters
            Employees
  Item 2   Properties
  Item 3   Legal Proceedings
  Item 4   Submission of Matters to 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
  Item 9A   Controls and Procedures
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 and Related Shareholder Matters
  Item 13   Certain Relationships and Related Transactions
  Item 14   Principal Accountant Fees and Services
PART IV    
  Item 15   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," "anticipates," "expects," "intends," "plans," and other similar words. We also disclose non-historical information that represents management's expectations, which are based on numerous assumptions. These statements and projections are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance or achievements to be materially different from those we project. These risks, uncertainties, and factors include, but are not limited to:

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

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



PART I

Item 1. Business


Overview

Constellation Energy is a North American energy company which includes a merchant energy business and BGE, its regulated electric and gas public utility in central Maryland.

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

1


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

        Our merchant energy business includes:

        BGE is a regulated electric transmission and distribution utility company and a regulated gas distribution utility company with a service territory that covers the City of Baltimore and all or part of ten counties in central Maryland. BGE was incorporated in Maryland in 1906.

        Our other nonregulated businesses:

        In addition, we own several investments that we do not consider to be core operations. These include financial investments, real estate projects, and interests in a Latin American power distribution project and in a fund that holds interests in two South American energy projects.

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

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

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

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


Operating Segments

The percentages of revenues, net income, and assets attributable to our operating segments are shown in the tables below. We present information about our operating segments, including certain special items, in Note 3 to Consolidated Financial Statements.

 
  Unaffiliated Revenues
 
 
  Merchant
Energy

  Regulated
Electric

  Regulated
Gas

  Other
Nonregulated

 
2003   67 % 20 % 7 % 6 %
2002   35   42   12   11  
2001   16   53   17   14  
 
  Net Income (1)
 
 
  Merchant
Energy

  Regulated
Electric

  Regulated
Gas

  Other
Nonregulated

 
2003   66 % 23 % 9 % 2 %
2002   47   19   6   28  
2001   113   62   45   (120 )
 
  Total Assets
 
 
  Merchant
Energy

  Regulated
Electric

  Regulated
Gas

  Other
Nonregulated

 
2003   68 % 22 % 7 % 3 %
2002   65   24   7   4  
2001   59   25   8   8  
(1)
Excludes cumulative effects of changes in accounting principles as discussed in more detail in Item 8. Financial Statements and Supplementary Data.

2



Merchant Energy Business

Introduction

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

        Our merchant energy business:

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


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

Mid-Atlantic Fleet

We own 6,379 MW of fossil, nuclear and hydroelectric generation capacity in the PJM region. The output of these plants is managed by our wholesale marketing and risk management operation and is hedged through a combination of power sales to wholesale and retail market participants.

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

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

Plants with Power Purchase Agreements

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

        We purchased 100% of Nine Mile Point Unit 1 (609 MW) and 82% of Unit 2 (941 MW) in November 2001. The remaining interest in Nine Mile Point Unit 2 is owned by a subsidiary of the Long Island Power Authority. Unit 1 entered service in 1969 and Unit 2 in 1988. Nine Mile Point is located within the New York Independent System Operator (NYISO) region.

        We sell 90% of our share of Nine Mile Point's output to the former owners of the plant at an average price of nearly $35 per megawatt-hour (MWH) under agreements that terminate between 2009 and 2011. The agreements are unit contingent (if the output is not available because the plant is not operating, there is no requirement to provide output from other sources). The remaining 10% of Nine Mile Point's output is managed by our wholesale marketing and risk management operation and sold into the wholesale market.

3


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

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

        The license on Nine Mile Point's Unit 1 expires in 2009 and in 2026 on Unit 2. We have commenced a license extension initiative for both units with the objective of obtaining up to 20 years of additional operations. We expect to submit the license extension application to the NRC in the spring of 2004.

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

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

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

Competitive Supply

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

Origination of Structured Transactions

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

        These activities typically occur in regional markets in which end user customers' electricity rates have been deregulated and thereby separated from the cost of generation supply. These markets include:

        Contracts with these customers generally extend from one to ten years, but some can be longer. We currently have approximately 22,800 MW of load under contract for 2004.

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

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

4


Portfolio Management

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

        These activities involve the use of a variety of instruments, including:

        Active portfolio management allows our wholesale marketing and risk management operation the ability to:

Other

We hold up to a 50% ownership interest in 25 operating energy projects that consist of electric generation (primarily relying on alternative fuel sources), fuel processing, or fuel handling facilities and are either qualifying facilities under the Public Utility Regulatory Policies Act of 1978 or otherwise exempt from, or not subject to, the Public Utility Holding Company Act of 1935. In addition, we own 100% of a geothermal electric generating facility in Hawaii. Each electric generating plant sells its output to a local utility under long-term contracts.

        We also provide the following services:

Fuel Sources

Our power plants use diverse fuel sources. Our fuel mix based on capacity owned at December 31, 2003 and our generation based on actual output by fuel type in 2003 were as follows:

Fuel

  Capacity Owned
  Generation
 
Nuclear   27 % 50 %
Coal   24   36  
Natural Gas   31   7  
Oil   6   1  
Renewable and Alternative (1)   3   4  
Dual (2)   9   2  
(1)
Includes solar, geothermal, hydro, biomass, and waste-to-energy.

(2)
Switches between natural gas and oil.

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

Nuclear

The output at Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) over the past five years has been:

 
  Generation
MWH

  Capacity
Factor

 
2003   13,653,338   93 %
2002   12,087,408   82  
2001   13,648,932   92  
2000   13,826,046   93  
1999   13,309,306   91  

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

 
  Generation
MWH*

  Capacity
Factor

 
2003   12,169,637   90 %
2002   11,727,567   87  
2001   11,613,519   86  
2000   11,243,095   83  
1999   10,766,425   79  

*represents our proportionate ownership interest

5


        The supply of fuel for nuclear generating stations includes the:


Uranium:   We have under contract sufficient quantities of uranium (concentrates and uranium hexafluoride) to meet 100% of both Calvert Cliffs' and Nine Mile Point's requirements through 2004, 45% for both plants in 2005, 60% for both plants in 2006, and 25% for both plants in 2007. In late 2003, the federally designated Russian export agent responsible for nuclear fuel terminated their contract with one of our key uranium hexafluoride suppliers located in the United States. This action will likely impact uranium hexafluoride deliveries from this supplier throughout the term of our agreement. Prices have increased due to this event and will adversely impact our future costs of uranium hexafluoride. The uranium hexafluoride that was scheduled to be delivered from this supplier in 2004 represents approximately 27% of our requirements for that year. We are currently evaluating our options to acquire alternate uranium hexafluoride supplies to meet our requirements.
Conversion:   We have contractual commitments providing for the conversion of all of our uranium concentrates into uranium hexafluoride for Calvert Cliffs and Nine Mile Point through 2004. We do not have requirements for conversion beyond 2004 because we currently do not expect to purchase uranium concentrates beyond 2004.
Enrichment:   We have contractual commitments that provide 100% of Calvert Cliffs' and Nine Mile Point's uranium enrichment requirements through 2006 and 25% of these requirements for both plants in 2007 and 2008.
Fuel Assembly
Fabrication:
  We have contracted for the fabrication of fuel assemblies for reloads required through 2013 at Calvert Cliffs and through 2008 for Nine Mile Point.

        The nuclear fuel markets are competitive and although prices for uranium and conversion are increasing, we do not anticipate any problem in meeting our future requirements.

Storage of Spent Nuclear Fuel—Federal Facilities
One of the issues associated with the operation and decommissioning of nuclear generating facilities is disposal of spent nuclear fuel. There are no facilities for the reprocessing or permanent disposal of spent nuclear fuel currently in operation in the United States, and the Nuclear Regulatory Commission (NRC) has not licensed any such facilities. The Nuclear Waste Policy Act of 1982 (NWPA) required the federal government through the Department of Energy (DOE), to develop a repository for, and disposal of, spent nuclear fuel and high-level radioactive waste.

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

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

Storage of Spent Nuclear Fuel—On-Site Facilities
Calvert Cliffs has a license from the NRC to operate an on-site independent spent fuel storage installation that expires in 2012. We have storage capacity at Calvert Cliffs that will accommodate spent fuel from operations through 2008. In addition, we can expand our temporary storage capacity at Calvert Cliffs to meet future requirements until approximately 2025. Currently, Nine Mile Point does not have independent spent fuel storage capacity. Rather, Nine Mile Point's Unit 1 has sufficient storage capacity within the plant until the end of its current operating license in 2009. If license renewal is obtained, independent spent fuel storage capability will need to be developed. Nine Mile

6



Point's Unit 2 has sufficient storage capacity within the plant until 2012. After that time independent spent fuel storage capability may need to be developed.

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

Cost for Decommissioning
We are obligated to decommission our nuclear plants at the time these plants cease operation. Both Calvert Cliffs and Nine Mile Point are required by the NRC to demonstrate reasonable assurance that funds will be available to decommission the sites. When BGE transferred all of its nuclear generating assets to our merchant energy business, it also transferred the trust fund established to pay for decommissioning Calvert Cliffs. At December 31, 2003, the trust fund assets were $284.9 million.

        Under the Maryland Public Service Commission's (Maryland PSC) order regarding the deregulation of electric generation, BGE ratepayers must pay a total of $520 million, in 1993 dollars, adjusted for inflation, to decommission Calvert Cliffs through fixed annual collections of approximately $18.7 million until June 30, 2006, and thereafter in an annual amount determined by reference to specified factors. BGE is collecting this amount on behalf of Calvert Cliffs. Any costs to decommission Calvert Cliffs in excess of this $520 million must be paid by Calvert Cliffs. If BGE ratepayers have paid more than this amount at the time of decommissioning, Calvert Cliffs must refund the excess. If the cost to decommission Calvert Cliffs is less than the amount BGE's ratepayers are obligated to pay, Calvert Cliffs may keep the difference.

        The sellers of Nine Mile Point transferred a $441.7 million decommissioning trust fund at the time of sale. In return, Nine Mile Point assumed all liability for the costs to decommission Unit 1 and 82% of the cost to decommission Unit 2. We believe that this amount is adequate to cover our responsibility for decommissioning Nine Mile Point to a greenfield status (restoration of the site so that it substantially matches the natural state of the surrounding properties and the site's intended use). At December 31, 2003, the Nine Mile Point trust fund assets were $451.2 million.

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

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

 
  Approximate
Annual Coal
Requirement
(tons)

  Special Coal
Restrictions

Brandon Shores
Units 1 and 2
    (combined)
  3,500,000   Sulfur content less than 1.20 lbs per mmBTU
C. P. Crane
Units 1 and 2
    (combined)
  850,000   Low ash melting temperature
H. A. Wagner
Units 2 and 3
    (combined)
  1,100,000   Sulfur content no more than 1%

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

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

7


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

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

Gas
We purchase natural gas, storage capacity, and transportation, as necessary, for electric generation at certain plants. Some of our gas-fired units can use residual fuel oil or distillates instead of gas. Gas is purchased under contracts with suppliers on the spot market and forward markets, including financial exchanges and bilateral agreements. The actual fuel quantities required can vary substantially from year to year depending upon the relationship between energy prices and fuel costs, weather conditions, and operating requirements. However, we believe that we will be able to obtain adequate quantities of gas to meet our requirements.

Oil
Under normal burn practices, our requirements for residual fuel oil (No. 6) amount to approximately 1.5 million to 2.0 million barrels of low-sulfur oil per year. Deliveries of residual fuel oil are made from the suppliers' Baltimore Harbor marine terminal for distribution to the various generating plant locations. Also, based on normal burn practices, we require approximately 5.0 million to 6.0 million gallons of distillates (No. 2 oil and kerosene) annually, but these requirements can vary substantially from year to year depending upon the relationship between energy prices and fuel costs, weather conditions, and operating requirements. Distillates are purchased from the suppliers' Baltimore truck terminals for distribution to the various generating plant locations. We have contracts with various suppliers to purchase oil at spot prices, and for future delivery, to meet our requirements.

Competition

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

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

        With respect to power generation, we compete in the operation of energy-producing projects, and our competitors in this business are both domestic and international organizations, including various utilities, industrial companies and independent power producers (including affiliates of utilities), some of which have financial resources that are greater than ours.

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

        Increased competition that resulted from some of these initiatives in several states contributed in some instances to a reduction in electricity prices and put pressure on electric utilities to lower their costs, including the cost of purchased electricity. Some states that were considering deregulation have slowed their plans or postponed consideration of deregulation. In addition, other states are reconsidering deregulation.

        We believe there is adequate growth potential in the current deregulated market. However, in response to regional market differences and to promote competitive markets, the Federal Energy Regulatory Commission (FERC) proposed initiatives promoting the formation of Regional Transmission Organizations and a standard market design. If approved, these market changes could provide additional opportunities for our merchant energy business.

        As the economy continues to recover and the market for commercial and industrial supply continues to grow, we have experienced increased competition in our retail commercial and industrial supply activities. The increase in retail competition may affect the margins that we will realize from our customers. However, we believe that our experience and expertise in assessing and managing risk will help us to remain competitive during volatile or otherwise adverse market circumstances.

8


Merchant Energy Operating Statistics

 
  2003
  2002
  2001
  2000
  1999

Revenues (In millions)                              
  Mid-Atlantic Fleet   $ 1,774.5   $ 1,415.1   $ 1,379.2   $ 731.7   $
  Plants with Power Purchase Agreements     620.0     456.4     70.8        
  Competitive Supply—Accrual Revenues     5,157.1     623.4     59.2        
                                 —Mark-to-Market Revenues     51.4     238.1     175.8     151.5     147.7
  Other     45.1     56.4     80.5     142.5     129.6

Total Revenues   $ 7,648.1   $ 2,789.4   $ 1,765.5   $ 1,025.7   $ 277.3

Generation (In millions)—MWH     51.6     44.7     37.4     18.8     1.3

        Operating statistics do not reflect the elimination of intercompany transactions.



Baltimore Gas and Electric Company

BGE is an electric transmission and distribution utility company and a gas distribution utility company with a service territory that covers the City of Baltimore and all or part of ten counties in central Maryland. BGE is regulated by the Maryland Public Service Commission (Maryland PSC) and FERC with respect to rates and other aspects of its business.

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

        BGE's electric and gas revenues come from many customers—residential, commercial, and industrial. In 2003, BGE's largest electric customer provided approximately four percent of BGE's total electric revenues. In 2003, BGE's largest gas customer provided approximately one percent of BGE's total gas revenues.

Electric Business

Electric Regulatory Matters and Competition

Deregulation

Effective July 1, 2000, electric customer choice and competition among electric suppliers was implemented in Maryland. As a result of the deregulation of electric generation, the following occurred effective July 1, 2000:

Standard Offer Service

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

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

9


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

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

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

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

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

Electric Load Management

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

        BGE generally activates these programs on summer days when demand and/or wholesale prices are relatively high. The reduction in the summer 2003 peak load from active load management was approximately 342 MW.

Transmission and Distribution Facilities

BGE maintains approximately 250 substations and 1,300 circuit miles of transmission lines throughout central Maryland. BGE also maintains nearly 22,900 circuit miles of distribution lines. The transmission facilities are connected to those of neighboring utility systems as part of the PJM Interconnection. Under the PJM Tariff and various agreements, BGE and other market participants can use regional transmission facilities for energy, capacity and ancillary services transactions including emergency assistance.

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

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Electric Operating Statistics

 
  2003
  2002
  2001
  2000(A)
  1999(A)

Revenues (In millions)                              
  Residential   $ 959.0   $ 946.6   $ 885.3   $ 922.6   $ 975.2
  Commercial     760.3     809.5     903.0     926.2     939.3
  Industrial     155.2     169.6     218.1     203.6     204.3

  System Sales     1,874.5     1,925.7     2,006.4     2,052.4     2,118.8
  Interchange Sales                 53.8     112.1
  Other (B)     47.1     40.3     33.6     29.0     29.1

    Total   $ 1,921.6   $ 1,966.0   $ 2,040.0   $ 2,135.2   $ 2,260.0

Sales (In thousands)—MWH                              
  Residential     12,754     12,652     11,714     11,675     11,349
  Commercial     14,919     14,602     14,147     14,042     13,565
  Industrial     4,336     4,475     4,445     4,476     4,350

  System Sales     32,009     31,729     30,306     30,193     29,264

Customers (In thousands)                              
  Residential     1,061.7     1,052.3     1,040.5     1,033.4     1,021.4
  Commercial     112.1     110.8     110.9     108.9     107.7
  Industrial     4.9     4.9     5.0     5.0     4.7

    Total     1,178.7     1,168.0     1,156.4     1,147.3     1,133.8

        Operating statistics do not reflect the elimination of intercompany transactions.


Gas Business

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

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

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

        For customers that buy their gas from BGE, there is a market-based rates incentive mechanism. Under market-based rates, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers. BGE must secure fixed-price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for the November through March period.

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

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

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

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

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

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


Gas Operating Statistics

 
  2003
  2002
  2001
  2000
  1999

Revenues (In millions)                              
  Residential                              
    Excluding Delivery Service   $ 444.5   $ 342.1   $ 378.4   $ 328.4   $ 298.1
    Delivery Service     13.6     16.5     16.3     23.5     11.5
  Commercial                              
    Excluding Delivery Service     128.6     89.4     115.5     97.9     79.3
    Delivery Service     24.6     29.2     21.4     25.8     24.4
  Industrial                              
    Excluding Delivery Service     11.5     9.3     12.8     10.9     8.2
    Delivery Service     11.4     13.9     13.8     16.3     16.1

  System Sales     634.2     500.4     558.2     502.8     437.6
  Off-system Sales     84.8     74.8     113.6     101.0     42.9
  Other     7.0     6.1     8.9     7.8     7.6

  Total   $ 726.0   $ 581.3   $ 680.7   $ 611.6   $ 488.1

Sales (In thousands)—DTH                              
  Residential                              
    Excluding Delivery Service     40,894     35,364     33,147     34,561     34,272
    Delivery Service     6,640     6,404     7,201     9,209     4,468
  Commercial                              
    Excluding Delivery Service     13,895     11,583     12,334     13,186     11,733
    Delivery Service     29,138     28,429     25,037     22,921     20,288
  Industrial                              
    Excluding Delivery Service     1,143     1,207     1,386     1,386     1,367
    Delivery Service     18,399     23,689     23,872     32,382     33,118

  System Sales     110,109     106,676     102,977     113,645     105,246
  Off-system Sales     12,859     18,551     20,012     22,456     15,543

      Total     122,968     125,227     122,989     136,101     120,789

Customers (In thousands)                              
  Residential     575.2     567.3     558.7     553.7     543.5
  Commercial     41.1     40.7     40.2     40.1     39.9
  Industrial     1.2     1.3     1.4     1.4     1.3

  Total     617.5     609.3     600.3     595.2     584.7

        Operating statistics do not reflect the elimination of intercompany transactions.

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Franchises

BGE has nonexclusive electric and gas franchises to use streets and other highways that are adequate and sufficient to permit them to engage in their present business. Conditions of the franchises are satisfactory.



Other Nonregulated Businesses

Energy Products and Services

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

Home Products and Gas Retail Marketing

We offer services to customers including:



District Cooling Services

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

Other

Our other nonregulated businesses include investments that we do not consider to be core operations. These include financial investments, real estate projects, and interests in a Latin American distribution project and in a fund that holds interests in two South American energy projects. While our intent is to dispose of these assets, market conditions and other events beyond our control may affect the actual sale of these assets. In addition, a future decline in the fair value of these assets could result in additional losses.



Consolidated Capital Requirements

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

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



Environmental Matters

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

        The development (involving site selection, environmental assessments, and permitting), construction, acquisition, and operation of electric generating and distribution facilities are subject to extensive federal, state, and local environmental and land use laws and regulations. From the beginning phases of siting and developing, to the ongoing operation of existing or new electric generating and distribution facilities, our activities involve compliance with diverse laws and regulations that address emissions and impacts to air and water, special, protected and cultural resources (such as wetlands, endangered species, and archeological/historical resources), chemical, and waste handling and noise impacts.

       
        Our activities require complex and often lengthy processes to obtain approvals, permits, or licenses for new, existing, or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires preparation of release prevention plans and emergency response procedures. We continuously monitor federal and state environmental initiatives in order to provide input as well as to maintain a proactive view of the future which is key to effective strategic planning. Additionally, as new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or their operation, as required.

        Our capital expenditures (excluding allowance for funds used during construction) were approximately $260 million during the five-year period 1999-2003 to comply with existing environmental standards and regulations.

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Clean Air Act

The Clean Air Act affects both existing generating facilities and new projects. The Clean Air Act and many state laws impose significant requirements relating to emissions of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter, and other pollutants that result from burning fossil fuels. The Clean Air Act also contains other provisions that could materially affect some of our projects. Various provisions may require permits, inspections, or installation of additional pollution control technology or may require the purchase of emission allowances. Certain of these provisions are described in more detail below.

        On October 27, 1998, the Environmental Protection Agency (EPA) issued a rule requiring 22 Eastern states and the District of Columbia to reduce emissions of NOx. The EPA rule requires states to implement controls sufficient to meet their NOx budget by May 30, 2004. However, the Northeast states decided to require compliance in 2003. Coal-fired power plants are a principal target of NOx reductions under this initiative.

        Many of our generation facilities are subject to NOx reduction requirements under the EPA rule, including those located in Maryland and Pennsylvania. At the Brandon Shores and Wagner facilities, we installed emission reduction equipment for our coal-fired units to meet Maryland regulations issued pursuant to the EPA's rule. The owners of the Keystone plant in Pennsylvania completed the installation of emissions reduction equipment by July 2003 to meet Pennsylvania regulations issued pursuant to the EPA's rule. Our total cost of the emissions reduction equipment at the Keystone plant was approximately $37 million.

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

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

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

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

        Based on the level of emissions control that the EPA and states are seeking in these new source review enforcement actions, we believe that material additional costs and penalties could be incurred if the EPA was successful in any future actions regarding our facilities.

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

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

14


which alternative is selected. We believe final regulations could be issued in 2004 and could affect all oil-fired and coal-fired boilers. The cost of compliance with the final regulations could be material.

        Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies by plant type. Fossil fuel-fired power plants are significant sources of carbon dioxide emissions, a principal greenhouse gas. Our compliance costs with any mandated federal greenhouse gas reductions in the future could be material.

Clean Water Act

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

        In April 2002, the EPA proposed rules under the Clean Water Act that require that cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. In February 2004, the proposed rules were finalized. The final rules require the installation of additional intake screens or other protective measures, as well as extensive site-specific study and monitoring requirements. We are currently reviewing the final rules and their potential impact to us. Our compliance costs associated with the final rules could be material.

        Under current provisions of the Clean Water Act, existing permits must be renewed at least every five years, at which time permit limits come under extensive review and can be modified to account for more stringent regulations. In addition, the permits can be modified at any time. Changes to the water discharge permits of our coal or other fuel suppliers due to federal or state initiatives may increase the cost of fuel, which in turn could have a significant impact on our operations.

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

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

Metal Bank

In the early 1970s, BGE shipped an unknown number of scrapped transformers to Metal Bank of America, a metal reclaimer in Philadelphia. Metal Bank's scrap and storage yard has been found to be contaminated with oil containing high levels of PCBs (hazardous chemicals frequently used as a fire resistant coolant in electrical equipment). On December 7, 1987, the EPA notified BGE and nine other utilities that they are considered potentially responsible parties (PRPs) with respect to the clean-up of the site. BGE, along with the other PRPs, submitted a remedial investigation and feasibility study to the EPA on October 14, 1994, and the EPA issued its Record of Decision (ROD) recommending clean-up for the site on December 31, 1997. On June 26, 1998, the EPA ordered BGE, the other utility PRPs, and the owner/operator to implement the requirements of the ROD. The utility PRPs have submitted the remedial design to EPA. Based on the ROD, BGE's share of the reasonably possible clean-up costs, estimated to be approximately 15.47%, could be as much as $1.3 million higher than amounts we believe are probable and have recorded as a liability in our Consolidated Balance Sheets.

Kane and Lombard Streets

A suit was originally filed by the EPA under CERCLA in October 1989 against BGE and several other defendants in the U.S. District Court for the District of Maryland, seeking to recover past and future clean-up costs at the Kane and Lombard Street site located in Baltimore City, Maryland. The State of Maryland filed a similar complaint in the same case and court in February 1990. The complaints alleged that BGE arranged for coal fly ash to be deposited on the site. The Court dismissed these complaints in November 1995. Maryland began additional investigation on the remainder of the site for the EPA, but never completed the investigation. BGE, along with three other defendants, agreed to complete a remedial investigation and feasibility study of groundwater contamination around the site in a July 1993 consent order. The remedial investigation report and a draft feasibility study were submitted to the EPA in February 2002. In December 2002, the EPA released its proposed remedy for the site and estimated the total clean-up cost for the site to be $6.2 million.

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

15


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

68th Street Dump

In July 1999, the EPA notified BGE, along with 19 other entities, that it may be a potentially responsible party at the 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. In April 2003, EPA re-proposed the 68th Street site for listing as a federal Superfund site, but decided not to include the site in its September 2003 update. BGE and other potentially responsible parties are pursuing alternatives to listing as a federal Superfund site, but at this stage, it is not possible to predict the outcome of those discussions, the clean-up cost of the site, or BGE's share of the liability. However, the costs could have a material effect on our, or BGE's, financial results.

Spring Gardens

In the past, predecessor gas companies (which were later merged into BGE) manufactured coal gas for residential and industrial use. The Spring Gardens site, located in Baltimore, Maryland, was once used to manufacture gas from coal and oil. The residue from this manufacturing process was coal tar, previously thought to be harmless but now found to contain a number of chemicals designated by the EPA as hazardous substances.

        In late December 1996, BGE signed a consent order with the Maryland Department of the Environment that required BGE to implement remedial action plans for contamination at and around the Spring Gardens site. BGE submitted the required remedial action plans, and they have been approved by the Maryland Department of the Environment. Based on these plans, the costs BGE considers to be probable to remedy the contamination are estimated to total $47 million. BGE recorded these costs as a liability in its Consolidated Balance Sheets and deferred these costs, net of accumulated amortization and amounts it recovered from insurance companies, as a regulatory asset. Through December 31, 2003, BGE spent approximately $39 million for remediation at this site.

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

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


Employees

Constellation Energy and its subsidiaries had, at December 31, 2003, approximately 8,650 employees. At the Nine Mile Point plant, approximately 700 employees are represented by the International Brotherhood of Electrical Workers, Local 97. The labor contract with this union expires in June 2006. We believe that our relationship with this union is satisfactory, but there can be no assurances that this will continue to be the case.

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Item 2. Properties

Constellation Energy's corporate offices occupy approximately 85,000 square feet of leased office space in Baltimore, Maryland. The corporate offices for most of our merchant energy business occupy approximately 110,000 square feet of leased office space in another building in Baltimore, Maryland. We describe our electric generation properties on the next page. We also have leases for other offices and services located in the Baltimore metropolitan region, and for various real property and facilities relating to our generation projects.

        BGE's principal headquarters building is located in downtown Baltimore. In January 2004, BGE sold a portion of its headquarters building and will consolidate its operations into the remainder of the building. In addition, BGE owns propane air and liquefied natural gas facilities as discussed in Item 1. Business—Gas Business section.

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

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

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

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

        We also lease office space throughout North America to support our merchant energy business.

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        The following table describes our generating facilities:

Plant

  Location
  Installed
Capacity (MW)

  % Owned
  Capacity
Owned (MW)

  Primary
Fuel

 
   
  (at December 31, 2003)

   
  (at December 31, 2003)

   
Mid-Atlantic Fleet                    
  Calvert Cliffs   Calvert Co., MD   1,685   100.0   1,685   Nuclear
  Brandon Shores   Anne Arundel Co., MD   1,286   100.0   1,286   Coal
  H. A. Wagner   Anne Arundel Co., MD   1,020   100.0   1,020   Coal/Oil/Gas
  C. P. Crane   Baltimore Co., MD   399   100.0   399   Oil/Coal
  Keystone   Armstrong and Indiana Cos., PA   1,711   21.0   359  (A) Coal
  Conemaugh   Indiana Co., PA   1,711   10.6   181  (A) Coal
  Perryman   Harford Co., MD   360   100.0   360   Oil/Gas
  Riverside   Baltimore Co., MD   249   100.0   249   Oil/Gas
  Handsome Lake   Rockland Twp, PA   250   100.0   250   Gas
  Notch Cliff   Baltimore Co., MD   128   100.0   128   Gas
  Westport   Baltimore City, MD   121   100.0   121   Gas
  Philadelphia Road   Baltimore City, MD   64   100.0   64   Oil
  Safe Harbor   Safe Harbor, PA   416   66.7   277   Hydro
       
     
   
Total Mid-Atlantic Fleet       9,400       6,379    

Plants with Power Purchase Agreements

 

 

 

 

 

 

 

 
  High Desert   Victorville, CA   830   100.0   830   Gas
  Nine Mile Point Unit 1   Scriba, NY   609   100.0   609   Nuclear
  Nine Mile Point Unit 2   Scriba, NY   1,148   82.0   941   Nuclear
  Oleander   Brevard Co., FL   680   100.0   680   Oil/Gas
  University Park   Chicago, IL   300   100.0   300   Gas
       
     
   
Total Plants with Power Purchase Agreements   3,567       3,360    

Competitive Supply

 

 

 

 

 

 

 

 

 

 
  Rio Nogales   Seguin, TX   800   100.0   800   Gas
  Holland Energy   Shelby Co., IL   665   100.0   665   Gas
  Big Sandy   Neal, WV   300   100.0   300   Gas
  Wolf Hills   Bristol, VA   250   100.0   250   Gas
       
     
   
Total Competitive Supply   2,015       2,015    

Other

 

 

 

 

 

 

 

 

 

 
  Puna I   Hilo, HI   30   100.0   30   Geothermal
  Panther Creek   Nesquehoning, PA   83   50.0   42   Waste Coal
  Colver   Colver Township, PA   110   25.0   28   Waste Coal
  Sunnyside   Sunnyside, UT   53   50.0   26   Waste Coal
  ACE   Trona, CA   102   30.3   31   Coal
  Jasmin   Kern Co., CA   33   50.0   17   Coal
  POSO   Kern Co., CA   33   50.0   17   Coal
  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
  Soda Lake I   Fallon, NV   3   50.0   2   Geothermal
  Soda Lake II   Fallon, NV   13   50.0   7   Geothermal
  Rocklin   Placer Co., CA   24   50.0   12   Biomass
  Fresno   Fresno, CA   24   50.0   12   Biomass
  Chinese Station   Sonora, CA   22   45.0   10   Biomass
  Malacha   Muck Valley, CA   32   50.0   16   Hydro
  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
       
     
   
Total Other       684       274    
       
     
   
Total Generating Facilities       15,666       12,028    
       
     
   
(A)
Reflects our proportionate interest in and entitlement to capacity from Keystone and Conemaugh, which include 2 megawatts of diesel capacity for Keystone and 1 megawatt of diesel capacity for Conemaugh.

18


        The following table describes our processing facilities:

Plant
  Location
  % Owned
  Primary
Fuel

A/C Fuels   Hazelton, PA   50.0   Coal Processing
Gary PCI   Gary, IN   24.5   Coal Processing
Low Country   Cross, SC   99.0   Synfuel 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   Wheelersburg, OH   16.7   Synfuel Processing
PC Synfuel WV III   Mayberry, WV   16.7   Synfuel Processing


Item 3. Legal Proceedings

We discuss our legal proceedings in Note 12 to Consolidated Financial Statements.



Item 4. Submission of Matters to Vote of Security Holders

Not applicable.


Executive Officers of the Registrant

Name

  Age
  Present Office
  Other Offices or Positions Held
During Past Five Years

Mayo A. Shattuck III   49   Chairman of the Board of Constellation Energy (since July 2002), President and Chief Executive Officer of Constellation Energy (since November 2001); and Chairman of the Board of BGE (since July 2002)   Co-Chairman and Co-Chief Executive Officer—DB Alex Brown, LLC and Deutsche Banc Securities, Inc., Vice Chairman—Bankers Trust Corporation.

E. Follin Smith

 

44

 

Executive Vice President (since January 2004) and Chief Financial Officer (since June 2001) and Chief Administrative Officer (since December 2003) of Constellation Energy and Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company (since January 2002)

 

Senior Vice President—Constellation Energy; 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.

Thomas V. Brooks

 

41

 

President of Constellation Power Source, Inc. (since October 2001); Executive Vice President of Constellation Energy (since January 2004)

 

Vice President of Business Development and Strategy—Constellation Energy; and Vice President—Goldman Sachs.

Frank O. Heintz

 

60

 

President and Chief Executive Officer of Baltimore Gas and Electric Company (since July 2000); Executive Vice President of Constellation Energy (since January 2004)

 

Executive Vice President, Utility Operations—BGE.

Michael J. Wallace

 

56

 

President of Constellation Generation Group, LLC (since January 2002); Executive Vice President of Constellation Energy (since January 2004)

 

Managing Director and Member—Barrington Energy Partners; and Senior Vice President—Commonwealth Edison.
             

19



Thomas F. Brady

 

54

 

Executive Vice President, Corporate Strategy and Development of Constellation Energy (since January 2004)

 

Senior Vice President, Corporate Strategy and Development—Constellation Energy; Vice President, Corporate Strategy and Development—Constellation Energy; Vice President, Corporate Strategy and Development—BGE.

Paul J. Allen

 

52

 

Senior Vice President, Corporate Affairs of Constellation Energy (since January 2004)

 

Vice President, Corporate Affairs—Constellation Energy; Senior Vice President and Group Head—Ogilvy Public Relations.

Kathleen A. Chagnon

 

44

 

Senior Vice President (since January 2004), General Counsel and Secretary (since August 2002), and Chief Compliance Officer (since November 2003) of Constellation Energy

 

Vice President—Constellation Energy; Vice President, Corporate Group General Counsel—The St. Paul Companies, Inc.

John R. Collins

 

46

 

Senior Vice President (since January 2004) and Chief Risk Officer of Constellation Energy (since December 2001)

 

Vice President—Constellation Energy; Managing Director—Finance—Constellation Power Source Holdings, Inc.; and Senior Financial Officer—Constellation Power Source, Inc.

Mark P. Huston

 

40

 

Vice President, Corporate Strategy and Development of Constellation Energy (since May 2002)

 

Manager, Corporate Strategy & Development—Constellation Energy; and Project Manager, Restructuring Project—BGE.

Marc C. Ugol

 

45

 

Senior Vice President, Human Resources of Constellation Energy (since January 2004)

 

Vice President, Human Resources—Constellation Energy; Senior Vice President, Human Resources and Administration—Tellabs, Inc.; and Senior Vice President, Human Resources—Platinum Technology International.

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

20



PART II

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

Stock Trading

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

        As of February 27, 2004, there were 48,287 common shareholders of record.

Dividend Policy

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

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

        In January 2004, we announced an increase in our quarterly dividend from $0.26 to $0.285 per share on our common stock payable April 1, 2004 to holders of record on March 10, 2004. This is equivalent to an annual rate of $1.14 per share.

        Quarterly dividends were declared on our common stock during 2003 and 2002 in the amounts set forth below.

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


Common Stock Dividends and Price Ranges

 
  2003
  2002
 
   
  Price*
   
  Price*
 
  Dividend
Declared

  Dividend
Declared

 
  High
  Low
  High
  Low
First Quarter   $ 0.26   $ 30.23   $ 25.17   $ 0.24   $ 31.18   $ 26.16
Second Quarter     0.26     34.92     27.50     0.24     32.38     27.65
Third Quarter     0.26     37.65     31.75     0.24     29.85     21.51
Fourth Quarter     0.26     39.61     35.03     0.24     29.02     19.30
   
             
           
Total   $ 1.04               $ 0.96            
   
             
           

* Based on New York Stock Exchange Composite Transactions.

21



Item 6. Selected Financial Data

Constellation Energy Group, Inc. and Subsidiaries

 
  2003
  2002
  2001
  2000
  1999
 

 
 
  (In millions, except per share amounts)

 
Summary of Operations                                
  Total Revenues   $ 9,703.0   $ 4,726.7   $ 3,878.8   $ 3,774.4   $ 3,830.9  
  Total Expenses     8,662.9     3,901.8     3,527.2     3,009.9     3,081.0  
  Net Gain on Sales of Investments and Other Assets     26.2     261.3     6.2     78.1     10.0  

 
  Income From Operations     1,066.3     1,086.2     357.8     842.6     759.9  
  Other Income     19.1     30.5     1.3     4.2     7.9  
  Fixed Charges     340.2     281.5     238.8     271.4     255.0  

 
  Income Before Income Taxes     745.2     835.2     120.3     575.4     512.8  
  Income Taxes     269.5     309.6     37.9     230.1     186.4  

 
  Income Before Extraordinary Item and Cumulative Effects of Changes in Accounting Principles     475.7     525.6     82.4     345.3     326.4  
  Extraordinary Loss, Net of Income Taxes                     (66.3 )
  Cumulative Effects of Changes in Accounting Principles, Net of Income Taxes     (198.4 )       8.5          

 
  Net Income   $ 277.3   $ 525.6   $ 90.9   $ 345.3   $ 260.1  

 
 
Earnings Per Common Share Assuming Dilution Before Extraordinary Item and Cumulative Effects of Changes in Accounting Principles

 

$

2.85

 

$

3.20

 

$

0.52

 

$

2.30

 

$

2.18

 
  Extraordinary Loss                     (0.44 )
  Cumulative Effects of Changes in Accounting Principles     (1.19 )       0.05          

 
  Earnings Per Common Share Assuming Dilution   $ 1.66   $ 3.20   $ 0.57   $ 2.30   $ 1.74  

 
  Dividends Declared Per Common Share   $ 1.04   $ 0.96   $ 0.48   $ 1.68   $ 1.68  

 

Summary of Financial Condition

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Total Assets   $ 15,800.7   $ 14,943.3   $ 14,697.5   $ 13,248.1   $ 10,011.4  

 
  Short-Term Borrowings   $ 9.6   $ 10.5   $ 975.0   $ 243.6   $ 371.5  

 
  Current Portion of Long-Term Debt   $ 343.2   $ 426.2   $ 1,406.7   $ 906.6   $ 808.3  

 
  Capitalization                                
    Long-Term Debt   $ 5,039.2   $ 4,613.9   $ 2,712.5   $ 3,159.3   $ 2,575.4  
    Minority Interests     113.4     105.3     101.7     97.7     95.2  
    Preference Stock Not Subject to Mandatory Redemption     190.0     190.0     190.0     190.0     190.0  
    Common Shareholders' Equity     4,140.5     3,862.3     3,843.6     3,174.0     3,017.5  

 
  Total Capitalization   $ 9,483.1   $ 8,771.5   $ 6,847.8   $ 6,621.0   $ 5,878.1  

 

Financial Statistics at Year End

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
 
Ratio of Earnings to Fixed Charges

 

 

2.98

 

 

3.33

 

 

1.18

 

 

2.78

 

 

2.87

 
 
Book Value Per Share of Common Stock

 

$

24.68

 

$

23.44

 

$

23.48

 

$

21.09

 

$

20.17

 

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

We discuss items that affect comparability between years, including acquisitions, accounting changes, including the impact of adopting Emerging Issues Task Force Issue (EITF) 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, and special items, in Item 7. Management's Discussion and Analysis.

22


Baltimore Gas and Electric Company and Subsidiaries

 
  2003
  2002
  2001
  2000(A)
  1999
 

 
 
  (In millions)

 

Summary of Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Total Revenues   $ 2,647.6   $ 2,547.3   $ 2,720.7   $ 2,746.8   $ 3,092.2  
  Total Expenses     2,262.6     2,181.0     2,408.9     2,334.4     2,387.9  

 
  Income From Operations     385.0     366.3     311.8     412.4     704.3  
  Other (Expense) Income     (5.4 )   10.7     0.4     7.5     8.4  
  Fixed Charges     111.2     140.6     154.6     184.0     205.9  

 
  Income Before Income Taxes     268.4     236.4     157.6     235.9     506.8  
  Income Taxes     105.2     93.3     60.3     92.4     178.4  

 
  Income Before Extraordinary Item     163.2     143.1     97.3     143.5     328.4  
  Extraordinary Loss, Net of Income Taxes                     (66.3 )

 
  Net Income     163.2     143.1     97.3     143.5     262.1  
  Preference Stock Dividends     13.2     13.2     13.2     13.2     13.5  

 
  Earnings Applicable to Common Stock   $ 150.0   $ 129.9   $ 84.1   $ 130.3   $ 248.6  

 

Summary of Financial Condition

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Total Assets   $ 4,706.6   $ 4,779.9   $ 4,954.5   $ 4,657.4   $ 7,273.4  

 
  Short-Term Borrowings   $   $   $   $ 32.1   $ 129.0  

 
  Current Portion of Long-Term Debt   $ 330.6   $ 420.7   $ 666.3   $ 567.6   $ 523.9  

 
  Capitalization                                
    Long-Term Debt   $ 1,343.7   $ 1,499.1   $ 1,821.7   $ 1,864.4   $ 2,206.0  
    Minority Interest     18.9     19.4     5.0     4.6     4.2  
    Preference Stock Not Subject to Mandatory Redemption     190.0     190.0     190.0     190.0     190.0  
    Common Shareholder's Equity     1,487.7     1,461.7     1,131.4     802.3     2,355.4  

 
  Total Capitalization   $ 3,040.3   $ 3,170.2   $ 3,148.1   $ 2,861.3   $ 4,755.6  

 

Financial Statistics at Year End

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Ratio of Earnings to Fixed Charges     3.36     2.66     1.99     2.27     3.45  
 
Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends

 

 

2.82

 

 

2.31

 

 

1.75

 

 

2.03

 

 

3.14

 

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

(A)
In July 2000, BGE transferred its generation assets, net of associated liabilities, to our merchant energy business as a result of the deregulation of electric generation.

23



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


Introduction and Overview

Constellation Energy Group, Inc. (Constellation Energy) is a North American energy company that conducts its business through various subsidiaries including a merchant energy business and Baltimore Gas and Electric Company (BGE). 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.

        Our merchant energy business is a competitive provider of energy solutions for large customers in North America. It has electric generation assets located in various regions of the United States and provides energy solutions to meet customers' needs. Our merchant energy business focuses on serving the full energy and capacity requirements (load-serving activities) of, and providing other risk management activities for various wholesale customers, such as utilities, municipalities, cooperatives, and retail aggregators, and for retail commercial and industrial customers. These load-serving activities typically occur in regional markets in which end use customer electricity rates have been deregulated and thereby separated from the cost of generation supply.

        Our wholesale marketing and risk management operation actively uses energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions. As part of our risk management activities we trade power and gas to enable price discovery and facilitate the hedging of our load-serving and other risk management products and services. Within our trading function we allow limited risk-taking activities for profit. These activities are actively managed through daily value at risk and liquidity position limits. We discuss value at risk in more detail later in the Market Risk section.

        BGE is a regulated electric transmission and distribution utility company and a regulated gas distribution utility company with a service territory that covers the City of Baltimore and all or part of ten counties in central Maryland.

        Our other nonregulated businesses:

        In addition, we own several investments that we do not consider to be core operations. These include financial investments, real estate projects, and interests in a Latin American distribution project and in a fund that holds interests in two South American energy projects.

        In this discussion and analysis, we will 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 2003, 2002, and 2001. Our 2003 results reflect a significant increase in revenues and operating expenses mainly due to the implementation of Emerging Issues Task Force Issue (EITF) 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities in January 2003, as well as the full year impact of our 2002 acquisitions, NewEnergy and Alliance. We discuss the cumulative effect of changes in accounting principles in Note 1 and our acquisitions in Note 15. We analyze and explain the differences between periods in the specific line items of our Consolidated Statements of Income.

        We have organized our discussion and analysis as follows:


Strategy

We are pursuing a balanced strategy to distribute energy through our North American competitive supply activities and our regulated utility located in Maryland, BGE. Our merchant energy business focuses on long-term, high-value sales of energy, capacity, and related products to large customers, including distribution utilities, municipalities, cooperatives, industrial customers, and commercial customers primarily in the regional markets in which end-use customer electricity rates have been deregulated and thereby separated from the cost of generation supply. These markets include:

24


        We obtain this energy through both owned and contracted generation. Our generation fleet is strategically located in deregulated markets across the country and is diversified by fuel type, including nuclear, coal, gas, oil, and renewable sources. Where we do not own generation, we contract for power from other merchant providers, typically through power purchase agreements. We intend to remain diversified between regulated transmission and distribution and competitive supply. We will use both our owned generation and our contracted generation to support our competitive supply operation.

        We are a leading national competitive supplier of energy in the deregulated markets previously discussed. In our wholesale and commercial and industrial retail marketing activities we are leveraging our recognized expertise in providing full requirements energy and energy related services to enter markets, capture market share, and organically grow these businesses. Through the application of technology, intellectual capital, and increased scale, we are seeking to reduce the cost of delivering full requirements energy and energy related services and managing risk.

        We are also responding proactively to customer needs by expanding the variety of products we offer. Our wholesale competitive supply activities include a growing customer products operation that markets physical energy products and risk management and logistics services sold to generators, distributors, producers of coal, natural gas and fuel oil, and other consumers.

        Within our retail competitive supply activities, we are marketing a broader array of products and expanding our markets. Over time, we may consider integrating the sale of electricity and natural gas to provide one energy procurement solution for our customers.

        Collectively, the integration of owned and contracted electric generation assets with origination, fuel procurement, and risk management expertise, allows our merchant energy business to earn incremental margin and more effectively manage energy and commodity price risk over geographic regions and over time. Our focus is on providing solutions to customers' energy needs, and our wholesale marketing and risk management operation adds value to our owned and contracted 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 wholesale marketing and risk management operation by providing a source of reliable power supply that provides a physical hedge for some of our load-serving activities.

        To achieve our strategic objectives, we expect to continue to pursue opportunities that expand our access to customers and to support our wholesale marketing and risk management operation with generation assets that have diversified geographic, fuel, and dispatch characteristics. We also expect to grow organically through selling a greater number of physical energy products and services to large energy customers. We expect to achieve operating efficiencies within our competitive supply operation and our generation fleet by selling more products through our existing sales force, benefiting from efficiencies of scale, adding to the capacity of existing plants, and making our business processes more efficient.

        We expect BGE and our other retail energy service businesses to grow through focused and disciplined expansion primarily from new customers. At BGE, we are also focused on enhancing reliability and customer satisfaction.

        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 the business environment and regulatory changes, and to maintain a strong balance sheet and investment-grade credit quality.

        Beginning in the fourth quarter of 2001, we undertook a number of initiatives to reduce our costs towards competitive levels and to ensure that our resources are focused on our core energy businesses. These initiatives included the implementation of workforce reduction programs, termination of all planned power plant development projects not under construction, the acceleration of our exit strategy for certain non-core assets, and the implementation of productivity initiatives.

        We are constantly reevaluating our strategies and might consider:


Business Environment

General Industry

Over the past several years, the utility industry and energy markets experienced significant changes as a result of less liquid and more volatile wholesale markets, credit quality deterioration of various industry participants, and the slowing of the U.S. economy.

        The energy markets also were affected by other significant events, including expanded investigations by state and federal authorities into business practices of energy companies in the deregulated power and gas markets relating to "wash trading" to inflate revenues and volumes, and other trading practices designed to manipulate market prices. In addition, several merchant energy businesses significantly reduced their energy trading activities due to deteriorating credit quality.

        During 2003, the energy markets continued to be highly volatile with significant changes in natural gas and power prices, as well as the continuation of reduced liquidity in the marketplace. We continue to actively manage our credit portfolio to attempt to reduce the impact of a potential counterparty default. We discuss our counterparty credit and other risks in more detail in the Market Risk section.

        We also continue to examine plans to achieve our strategies and to further strengthen our balance sheet and enhance our liquidity. We discuss our liquidity in the Financial Condition section.


Electric Competition

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

Maryland

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

25


Standard Offer Service

Our wholesale marketing and risk management operation is providing BGE with 100% of the energy and capacity required to meet its commercial and industrial standard offer service obligations through June 30, 2004 and 100% of the energy and capacity required to meet its residential standard offer service obligations through June 30, 2006. BGE will obtain its supply for standard offer service to its commercial and industrial customers beginning July 1, 2004, and to its residential customers beginning July 1, 2006, through a competitive wholesale bidding process as discussed in the Standard Offer Service—Provider of Last Resort (POLR) section below. Our wholesale marketing and risk management operation obtains the energy and capacity to supply BGE's standard offer service obligations from our merchant energy operating plants in the PJM Interconnection (PJM) region, supplemented with energy and capacity purchased from the wholesale market, as necessary.

        Beginning July 1, 2002, the fixed price standard offer service rate ended for certain of our large commercial and industrial customers. As a result, the majority of these customers purchase their electricity from alternate suppliers, including subsidiaries of Constellation Energy. The remaining large commercial and industrial customers that continue to receive their electric supply from BGE are charged market-based standard offer service rates through June 30, 2004.

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

Standard Offer Service—Provider of Last Resort (POLR)

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

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

Other States

Several states, other than Maryland, have supported deregulation of the electric industry. The pace of deregulation in other states varies based on historical moves to competition and responses to recent market events. Certain states that were considering deregulation have slowed their plans or postponed consideration. In addition, other states are reconsidering deregulation. Our merchant energy business is also affected by regional regulatory or legislative decisions, which may impact our financial results and our ability to successfully execute our growth strategy.

        In response to regional market differences and to promote competitive markets, the FERC proposed initiatives promoting the formation of Regional Transmission Organizations and a standard market design. If approved, these market changes could provide additional opportunities for our merchant energy business. We discuss these initiatives in the FERC Regulation—Regional Transmission Organizations and Standard Market Design section.


Gas Competition

The wholesale price of natural gas is not subject to regulation. All BGE gas customers have the option to purchase gas from alternate suppliers.

26



Regulation by the Maryland PSC

In addition to electric restructuring which was discussed earlier, regulation by the Maryland PSC influences BGE's businesses. The Maryland PSC determines the rates that BGE can charge customers for the electric distribution and gas businesses. The Maryland PSC incorporates into BGE's electric rates the transmission rates determined by FERC. BGE's electric rates are unbundled to show separate components for delivery service, competitive transition charges, standard offer service (generation), transmission, universal service, and certain taxes. The rates for BGE's regulated gas business continue to consist of a "base rate" and a "fuel rate."

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 costs 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.

        As a result of the deregulation of electric generation in Maryland, 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. We discuss the impact on base rates beyond 2004 in the Electric Competition—Maryland section.

Gas Fuel Rate

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 and a proceeding with the Maryland PSC in more detail in the Regulated Gas Business—Gas Cost Adjustments section and in Note 1.


FERC Regulation

Regional Transmission Organizations and Standard Market Design

In 1997, BGE turned over the operation of its transmission facilities to PJM, a power pool in the Mid-Atlantic region. In December 1999, FERC issued Order 2000, amending its regulations under the Federal Power Act to advance the formation of Regional Transmission Organizations (RTOs) that would allow easier access to transmission. PJM received FERC approval of its RTO status in December 2002 pending certain compliance filings.

        On July 31, 2002, the FERC issued a proposed rulemaking regarding implementation of a standard market design (SMD) for wholesale electric markets. The SMD rulemaking is intended to complement FERC's RTO order, and would require RTOs to substantially comply with its provisions. The SMD proposals also required transmission providers to turn over the operation of their facilities to an independent operator that will operate them consistent with a revised market structure proposed by the FERC. According to the FERC, the revised market structure will reduce inefficiencies caused by inconsistent market rules and barriers to transmission access. The FERC proposed that its rule be implemented in stages by October 1, 2004. Comments on the SMD proposal were submitted in February 2003.

        In April 2003, the FERC issued a report that indicated its position with respect to the proposed rulemaking and announced that it intends to leave relatively unmodified existing RTO practices, to allow flexibility among regional approaches, to allow phased-in implementation of the final rule, and to provide an increased deference to states' concerns. Concurrently, proposed federal legislation has been introduced that would remand the rulemaking process to FERC, require the issuance of a new notice of proposed rulemaking, and delay the issuance of a final rule until at least January 1, 2007.

        We believe that, while the original SMD proposal would have led to uniform rules that would have been largely favorable to Constellation Energy and BGE, the revised regional approach should result in improved market operations across various regions. The proposed federal legislation does not appear to exclude a regional approach to market development. Overall, the trend continues to be toward increased competition in the regions. The region where BGE operates is expected to be relatively unaffected by this proceeding, based on current compliance by the PJM with the SMD proposal.

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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 that may affect our ability to successfully execute our growth strategy. 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.

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. Weather affects residential sales more than commercial and industrial sales, which are mostly affected by business needs for electricity and gas. However, the Maryland PSC allows BGE 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 Regulated Gas Business—Weather Normalization section.

        BGE measures 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, adjusted for humidity levels. 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, 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 2003 and 2002, 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:

 
  2003
  2002
  30-year
Average

Cooling degree-days   755   1,006   839
Percentage change from prior year   (25.0)%    
Heating degree-days   5,140   4,542   4,729
Percentage change from prior year   13.2%    


Other Factors

A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative products for our merchant energy business. 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:

        Other factors, aside from weather, also 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.

        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 12 and Item 1. Business—Environmental Matters section. You will find details of our legal matters in Note 12. 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.

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Critical Accounting Policies

Our discussion and analysis of financial condition and results of operations is 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 numerous factors that are difficult to predict and are beyond management's control. As a result, actual amounts could materially differ from these estimates.

        The Securities and Exchange Commission (SEC) issued disclosure guidance for accounting policies that management believes are most "critical." The SEC defines 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 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 merchant energy business enters into contracts for energy, other energy-related commodities, and related derivatives. We record merchant energy business revenues using two methods of accounting: accrual accounting and mark-to-market accounting. We describe our use of accrual accounting (including hedge accounting) in more detail in Note 1.

        We record revenues using the mark-to-market method of accounting for derivative contracts for which we are not permitted to use accrual accounting or hedge accounting. These mark-to-market activities include derivative contracts for energy and other energy-related commodities. Under the mark-to-market method of accounting, we record the fair value of these derivatives as mark-to-market energy assets and liabilities at the time of contract execution. 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 consist of a combination of energy and energy-related 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 and quantities used to determine fair value reflect management's best estimate considering various factors. However, future market prices and actual quantities will vary from those used in recording mark-to-market energy assets and liabilities, and it is possible that such variations could be material.

        We record reserves to reflect uncertainties associated with certain estimates inherent in the determination of the fair value of mark-to-market energy assets and liabilities. The effect of these uncertainties is not incorporated in market price information or other market-based estimates used to determine fair value of our mark-to-market energy contracts. To the extent possible, we utilize market-based data together with quantitative methods for both measuring the uncertainties for which we record reserves and determining the level of such reserves and changes in those levels.

        We describe below the main types of reserves we record and the process for establishing each. Generally, increases in reserves reduce our earnings, and decreases in reserves increase our earnings. However, all or a portion of the effect on earnings of changes in reserves may be offset by changes in the value of the underlying positions.

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        Market prices for energy and energy-related commodities vary based upon a number of factors, and changes in market prices affect both the recorded fair value of our mark-to-market energy contracts and the level of future revenues and costs associated with accrual-basis activities. Changes in the value of our mark-to-market energy contracts will affect our earnings in the period of the change, while changes in forward market prices related to accrual-basis revenues and costs will affect our earnings in future periods to the extent those prices are realized. We cannot predict whether, or to what extent, the factors affecting market prices may change, but those changes could be material and could affect us either favorably or unfavorably. We discuss our market risk in more detail in the Market Risk section.

        In October 2002, the EITF reached a consensus on Issue 02-3. This consensus prohibits mark-to-market accounting for energy-related contracts that do not meet the definition of a derivative under Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. As a result, we began to account for all non-derivative contracts on the accrual basis of accounting effective January 1, 2003 as described in Note 1. The consensus also prohibits recording unrealized gains or losses at the inception of derivative contracts unless the fair value of each contract in its entirety is evidenced by quoted market prices or other current market transactions for contracts with similar terms and counterparties, and it requires gains and losses on derivative energy trading contracts (whether realized or unrealized) to be reported as revenue on a net basis in the income statement.

        EITF 02-3 affects the timing of recognizing earnings on non-derivative transactions. In general, beginning in 2003 earnings on non-derivative transactions subject to EITF 02-3 are no longer recognized at the inception of the transactions as they were under mark-to-market accounting because they are subject to accrual accounting and are recognized over the term of the transaction. As a result, while total earnings over the term of a transaction are the same as they would have been under mark-to-market accounting, our reported earnings for contracts subject to EITF 02-3 generally match the cash flows from those contracts more closely. Additionally, because we record revenues and costs on a gross basis under accrual accounting, our revenues and costs increased, but our earnings have not been affected by gross versus net reporting.

        The impact of derivative contracts on our revenues and costs is affected by many factors, including:

        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

Long-Lived Assets

We are required to evaluate certain assets that have long lives (for example, generating property and equipment and real estate) to determine if they are impaired when certain conditions exist. SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, provides the accounting for impairments of long-lived assets. We are required to test our long-lived assets for recoverability whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes are:

        For long-lived assets that are expected to be held and used, SFAS No. 144 provides that an impairment loss shall only be recognized if the carrying amount of an asset is not recoverable and exceeds its fair value. The carrying amount of an asset is not recoverable under SFAS No. 144 if the carrying amount

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exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. Therefore, when we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets. This necessarily involves judgment surrounding the inherent uncertainty of future cash flows.

        In order to estimate an asset's future cash flows, we consider historical cash flows, as well as reflect our understanding of the extent to which future cash flows will be either similar to or different from past experience based on all available evidence. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our other earnings forecasts). If we are considering alternative courses of action to recover the carrying amount of a long-lived asset (such as the potential sale of an asset), we probability-weight the alternative courses of action to estimate the cash flows.

        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 the assumptions used in our estimates, and the impact of such variations could be material.

        For long-lived assets that can be classified as assets to be disposed of by sale under SFAS No. 144, an impairment loss is recognized to the extent their carrying amount exceeds their fair value, including costs to sell.

        If we determine that the undiscounted cash flows from an asset to be held and used are less than the carrying amount of the asset, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. The estimation of fair value under SFAS No. 144, whether in conjunction with an asset to be held and used or with an asset to be disposed of by sale, also involves judgment. We consider quoted market prices in active markets to the extent they are available. In the absence of such information, we may consider prices of similar assets, consult with brokers, or employ other valuation techniques. Often, we will discount the estimated future cash flows associated with the asset using a single interest rate that is commensurate with the risk involved with such an investment or employ an expected present value method that probability-weights a range of possible outcomes. The use of these methods involves the same inherent uncertainty of future cash flows as discussed above with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in our estimates, and the impact of such variations could be material.

        We are also required to evaluate our equity-method and cost-method investments (for example, in partnerships that own power projects) to determine whether or not they are impaired. Accounting Principles Board Opinion (APB) No. 18, The Equity Method of Accounting for Investments in Common Stock, provides the accounting for these investments. The standard for determining whether an impairment must be recorded under APB No. 18 is whether the investment has experienced a loss in value that is considered an "other than a temporary" decline in value.

        The evaluation and measurement of impairments under the APB No. 18 standard involves the same uncertainties as described above for long-lived assets that we own directly and account for in accordance with SFAS No. 144. Similarly, the estimates that we make with respect to our equity and cost-method investments are subject to variation, and the impact of such variations could be material. Additionally, if the projects in which we hold these investments recognize an impairment under the provisions of SFAS No. 144, we would record our proportionate share of that impairment loss and would evaluate our investment for an other than temporary decline in value under APB No. 18.

Goodwill

Goodwill is the excess of the purchase price of an acquired business over the fair value of the net assets acquired. We do not amortize goodwill and certain other intangibles under the provisions of SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 requires us to evaluate goodwill for impairment at least annually or more frequently if events and circumstances indicate the business might be impaired. Goodwill is impaired if the carrying value of the business exceeds fair value. Annually, we estimate the fair value of the businesses we have acquired using techniques similar to those used to estimate future cash flows for long-lived assets as discussed above, which involves judgment. If the estimated fair value of the business is less than its carrying value, an impairment loss is required to be recognized to the extent that the carrying value of goodwill is greater than its fair value.


Asset Retirement Obligations

We incur legal obligations associated with the retirement of certain long-lived assets. SFAS No. 143, Accounting for Asset Retirement Obligations, provides the accounting for legal obligations associated with the retirement of long-lived assets. We incur such legal obligations as a result of environmental and other government regulations, contractual agreements, and other factors. The application of this standard requires significant judgment due to the large number and diverse nature of the assets in our various businesses and the estimation of future cash flows required to measure legal obligations associated with the retirement of specific assets.

        SFAS No. 143 requires the use of an expected present value methodology in measuring asset retirement obligations that involves judgment surrounding the inherent uncertainty of the probability, amount and timing of payments to settle these obligations, and the appropriate interest rates to discount future cash flows. We use our best estimates in identifying and measuring our asset retirement obligations in accordance with SFAS No. 143.

        Our nuclear decommissioning costs represent our largest asset retirement obligation. This obligation primarily results from the requirement to decommission and decontaminate the Calvert Cliffs and Nine Mile Point plants in connection with their future retirement. We revised our site-specific decommissioning cost estimates as part of the process to determine our nuclear asset retirement obligations. However, given the magnitude of the amounts involved, complicated and ever-changing technical and regulatory requirements, and the very long time horizons involved, the actual obligation could vary from the assumptions used in our estimates, and the impact of such variations could be material.

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Significant Events of 2003

In 2003, we recorded the following special items in earnings:

 
  Pre-
Tax

  After-
Tax

 

 
 
  (In millions)

 
Workforce reduction costs   $ (2.1 ) $ (1.3 )
Impairment losses and other costs     (0.6 )   (0.4 )
Net gain on sales of investments and other assets     26.2     16.4  

 
Total special items   $ 23.5   $ 14.7  

 


Workforce Reduction Costs

During 2003, we recorded costs of $2.1 million pre-tax, or $1.3 million after-tax, of which BGE recorded $0.7 million pre-tax, associated with deferred payments to employees eligible for the 2001 Voluntary Special Early Retirement Program.


Impairment Losses and Other Costs

In 2003, our other nonregulated businesses recognized an impairment loss of $0.6 million pre-tax, or $0.4 million after-tax, related to the decline in value of our investment in an airplane that we sold in January 2004.

        In the fourth quarter of 2003, we began re-evaluating our strategy regarding ourgeothermal generating facility in Hawaii. This facility has property, plant and equipment with a net book value of approximately $137 million. If we ultimately dispose of the geothermal facility, the actual proceeds received could be less than the carrying value of the plant, resulting in a loss that could be material. We discuss this in further detail in the Merchant Energy Business—Other section on page 42.


Net Gain on Sales of Investments and Other Assets

During 2003, our other nonregulated businesses recognized $26.2 million of pre-tax, or $16.4 million after-tax, gains on the sales of non-core assets as follows:

        We discuss our 2002 and 2001 special items in more detail in Note 2.


Hurricane Isabel

In September 2003, Hurricane Isabel caused damage to the electric and gas distribution systems of BGE. As a result, during 2003, BGE incurred capitalized costs of $32.0 million and maintenance expenses of $36.8 million pre-tax, or $22.2 million after-tax to restore its distribution system. The maintenance expenses included $32.1 million pre-tax, or $19.4 million after-tax, of incremental expenses.


Generating Facility Commenced Operations

In April 2003, our High Desert Power Project in Victorville, California, an 830 megawatt (MW) gas-fired combined cycle facility, commenced operations. The project has a long-term power sales agreement with the California Department of Water Resources (CDWR). The contract is a "tolling" structure, under which the CDWR pays a fixed amount of $12.1 million per month and provides CDWR the right, but not the obligation, to purchase power from the project at a price linked to the variable cost of production. During the term of the contract, which runs for seven years and nine months from the April 2003 commercial operation date of the plant, the project will provide energy exclusively to the CDWR.

        Prior to June 2003, we accounted for this project as an operating lease. In June 2003, we exercised our option to pay off the lease, acquired the assets from the lessor, and included the assets and liabilities in our Consolidated Balance Sheets. We describe the net assets acquired in Note 15. We include the results of the High Desert Power Project in our merchant energy business segment.


Acquisitions

During 2003, our merchant energy business acquired the following energy contract portfolios:

        On October 22, 2003, we purchased Blackhawk Energy Services (Blackhawk) and Kaztex Energy Management (Kaztex). Blackhawk and Kaztex are providers of natural gas and electricity products throughout Illinois and Wisconsin, serving approximately 1,100 customers representing approximately 70 billion cubic feet of natural gas and 0.9 million megawatt hours of electricity. We acquired 100% ownership of both companies for $26.9 million. We acquired cash of $1.2 million as part of the purchase. We describe the net assets acquired in Note 15. We include the results of Blackhawk and Kaztex in our merchant energy business segment beginning on the date of acquisition.

        In addition, as part of our growth strategy, our merchant energy business had other acquisitions including a synthetic fuel facility in South Carolina, various competitive energy supply contract portfolios with commercial and industrial customers, certain gas contracts and a wholesale marketing business in Canada.

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Planned Acquisition

On November 25, 2003, we announced an agreement with Rochester Gas and Electric (RG&E) to acquire the R.E. Ginna Nuclear Power Plant (Ginna) located north of Rochester, New York. Upon closing the acquisition of this 495 MW facility, we will own and operate three nuclear power stations. The estimated purchase price for the Ginna plant is $401 million, excluding approximately $22 million for purchased nuclear fuel. RG&E will transfer approximately $202 million in decommissioning funds at the time of closing. We believe this transfer will be sufficient to meet the decommissioning requirements of the facility.

        The transaction is contingent upon regulatory approvals, including license extension. The acquisition includes a long-term unit contingent power purchase agreement where we will sell 90% of the plant's output and capacity to RG&E for 10 years at an average price of $44.00 per MWH. The remaining 10% of the plant's output will be managed by our wholesale marketing and risk management operation and will be sold into the wholesale market.


Synthetic Fuel Tax Credits

We have investments in facilities that manufacture solid synthetic fuel produced from coal as defined under Section 29 of the Internal Revenue Code for which we claim tax credits on our Federal income tax return. We recognize the tax benefit of these credits in our Consolidated Statements of Income when we believe it is highly probable that the credits will be sustained. The synthetic fuel process involves combining coal material with a chemical reagent to create a significant chemical change. A taxpayer may request a private letter ruling from the Internal Revenue Service (IRS) to support its position that the synthetic fuel produced undergoes a significant chemical change and thus qualifies for Section 29 credits.

        As of December 31, 2003, we have recognized cumulative tax benefits associated with Section 29 credits of $78.0 million, of which $35.0 million was recognized during the year ended December 31, 2003. These credits relate to our minority ownership interest in four synthetic fuel facilities located in Ohio, Virginia and West Virginia. These facilities have received private letter rulings from the IRS. In January 2004, the IRS concluded its examination of the partnership that owns these facilities for the tax years 1998 through 2001 and the IRS did not disallow any of the previously recognized synthetic fuel credits. We are awaiting final written notice of the resolution of the examination from the IRS.

        In 2003, we purchased 99% ownership in a South Carolina facility that produces synthetic fuel. On January 12, 2004, we submitted our request for a private letter ruling to the IRS for our South Carolina facility. Our South Carolina facility is using the same synthetic fuel process that was utilized by the previous owner, which had received a private letter ruling. To date, we have not yet received our private letter ruling from the IRS for our South Carolina facility.

        Since we may not rely upon a private letter ruling issued by the IRS to another taxpayer, we have not recognized the tax benefit of approximately $36 million for these credits in our Consolidated Statements of Income during 2003. We have the option under the amended purchase agreement for this facility to terminate our participation, without penalty, by April 5, 2004. We are currently evaluating our strategy regarding this facility and have not decided whether we will end our participation.

        While we believe the production and sale of synthetic fuel from all of our synthetic fuel facilities meet the conditions to qualify for tax credits under Section 29 of the IRS Code, we cannot predict the timing or outcome of any future challenge by the IRS, legislative or regulatory action, or the ultimate impact of such events on the Section 29 credits that we have claimed to date or expect to claim in the future, but the impact could be material to our financial results.


Calvert Cliffs Extended Outage

In April 2003, our merchant energy business completed the Unit 2 steam generator replacement and refueling outage at Calvert Cliffs. This outage was completed in 66 days, 58 fewer days than a similar outage completed at Calvert Cliff's Unit 1 in June 2002.


Dividend Increase

In January 2004, we announced an increase in our quarterly dividend from 26 cents to 28.5 cents per share on our common stock payable April 1, 2004 to holders of record on March 10, 2004. This is equivalent to an annual rate of $1.14 per share.

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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. Significant changes in other income, fixed charges, and income taxes are discussed in the aggregate for all segments in the Consolidated Nonoperating Income and Expenses section.


Overview

Results

 
  2003
  2002
  2001
 

 
 
  (In millions, after-tax)
 
Merchant energy   $ 313.0   $ 247.2   $ 93.1  
Regulated electric     107.5     99.3     50.9  
Regulated gas     43.0     31.1     37.5  
Other nonregulated     12.2     148.0     (99.1 )

 
Net Income Before Cumulative Effects of Changes in Accounting Principles     475.7     525.6     82.4  
Cumulative Effects of Changes in Accounting Principles     (198.4 )       8.5  

 
Net Income   $ 277.3   $ 525.6   $ 90.9  

 
Special Items Included in Operations:                    
Net gain on sales of investments and other assets   $ 16.4   $ 166.7   $ 1.9  
Workforce reduction costs     (1.3 )   (38.0 )   (64.1 )
Impairments of real estate, senior-living, and other investments     (0.4 )   (1.2 )   (72.5 )
Impairments of investment in qualifying facilities and domestic power projects         (9.9 )   (30.5 )
Costs associated with exit of BGE Home merchandise stores         (6.1 )    
Contract termination related costs             (139.6 )

 
Total Special Items   $ 14.7   $ 111.5   $ (304.8 )

 

2003

Our total net income for 2003 decreased $248.3 million, or $1.54 per share, compared to 2002 mostly because of the following:

        These decreases were partially offset by the following:


2002

Our total net income for 2002 increased $434.7 million, or $2.63 per share, compared to 2001 mostly because of the following:

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        These increases were partially offset by special items recorded in 2002 and the following:

        In addition, our other nonregulated businesses recorded the following in 2001 that had a positive impact in that period:

        Earnings per share contributions from all of our business segments were impacted by the dilution resulting from the issuance of 13.2 million of common shares during 2001.


Merchant Energy Business

Background
Our merchant energy business is a competitive provider of energy solutions for large customers in North America. We discuss the impact of deregulation on our merchant energy business in the
Business Environment—Electric Competition section.

        We record merchant energy revenues and expenses in our financial results in different periods depending upon which portion of our business they affect. We discuss our revenue recognition policies in the Critical Accounting Policies section and in Note 1. We summarize our policies as follows:

        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 Competitive Supply—Mark-to-Market 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.

        In the first quarter of 2003, we adopted EITF 02-3, which requires non-derivative contracts to be accounted for on the accrual basis and recorded in our Consolidated Statements of Income gross rather than net. The primary contracts affected were our full requirements load-serving contracts and unit-contingent power purchase contracts. The majority of these contracts were in Texas and New England and were entered into prior to our shift to accrual accounting earlier in 2002. We discuss our shift to accrual accounting during 2002 in more detail in the Competitive Supply—Accrual Revenues and Fuel and Purchased Energy Expenses section. We discuss the adoption of EITF 02-3 in more detail in Note 1.

        After the re-designation of existing contracts to non-trading, we record revenues and expenses on a gross basis, but this does not have a material impact on earnings because the resulting increase in revenues is accompanied by a similar increase in fuel and purchased energy expenses.

        EITF 02-3 affects the timing of recognizing earnings on non-derivative transactions. Earnings on new non-derivative transactions subject to EITF 02-3 are no longer recognized at the inception of the transactions as they were under mark-to-market accounting because they are subject to accrual accounting and are recognized over the term of the transaction.

        Additionally, we expect lower earnings volatility for this portion of our business because unrealized changes in the fair value of non-derivative load-serving contracts will no longer be recorded as revenue at the time of the change as they were under mark-to-market accounting.

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Results

 
  2003
  2002
  2001
 

 
 
  (In millions)
 
Revenues   $ 7,648.1   $ 2,789.4   $ 1,765.5  
Fuel and purchased energy expenses     (5,672.5 )   (1,175.0 )   (484.5 )
Operations and maintenance expenses     (970.9 )   (787.4 )   (597.8 )
Workforce reduction costs     (1.2 )   (26.5 )   (46.0 )
Impairment losses and other costs         (14.4 )   (46.9 )
Contract termination related costs             (224.8 )
Depreciation and amortization     (229.5 )   (242.8 )   (174.9 )
Accretion of asset retirement obligations     (42.7 )        
Taxes other than income taxes     (103.0 )   (83.5 )   (49.4 )
Net loss on sales of assets         (3.7 )    

 
Income from Operations   $ 628.3   $ 456.1   $ 141.2  

 
Income before cumulative effects of changes in accounting principles (after-tax)   $ 313.0   $ 247.2   $ 93.1  
Cumulative effects of changes in accounting principles (after-tax)     (198.4 )        

 
Net Income   $ 114.6   $ 247.2   $ 93.1  

 
Special Items Included in Operations (after-tax)        
    Workforce reduction
    costs
  $ (0.7 ) $ (16.0 ) $ (28.0 )
    Impairment of investments in
    qualifying facilities and
    domestic power projects
        (9.9 )   (30.5 )
    Net loss on sales of assets         (2.4 )    
    Contract termination related
    costs
            (139.6 )

 
Total Special Items   $ (0.7 ) $ (28.3 ) $ (198.1 )

 

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.

Revenues and Fuel and Purchased Energy Expenses

Our merchant energy business manages the revenues we realize from the sale of energy to our customers and our costs of procuring fuel and energy. The difference between revenues and fuel and purchased energy expenses is the primary driver of the profitability of our merchant energy business. Accordingly, we believe it is appropriate to discuss the operating results of our merchant energy business by analyzing the changes in the relationship between revenues and fuel and purchased energy expenses. In managing our portfolio, we occasionally terminate, restructure, or acquire contracts. Such transactions are within the normal course of managing our portfolio and may materially impact the timing of our recognition of revenues and fuel and purchased energy expenses. We discuss non-fuel direct costs, such as ancillary services, transmission costs, brokerage fees, and legal costs in conjunction with other operations and maintenance expenses later in the Operations and Maintenance Expenses section.

        We analyze our merchant energy revenues and fuel and purchased energy expenses in the following categories because of the risk profile of each category, differences in the revenue sources, and the nature of fuel and purchased energy expenses. With the exception of a portion of our competitive supply activities that we are required to account for using the mark-to-market method of accounting, all of these activities are accounted for on an accrual basis.

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        We provide a summary of our revenues and fuel and purchased energy expenses as follows:

 
  2003
   
  2002
   
  2001
   
 

 
 
  (Dollar amounts in millions)
 
Revenues:                                
  Mid-Atlantic Fleet   $ 1,774.5       $ 1,415.1       $ 1,379.2      
  Plants with Power Purchase Agreements     620.0         456.4         70.8      
  Competitive Supply     5,208.5         861.5         235.0      
  Other     45.1         56.4         80.5      

 
  Total   $ 7,648.1       $ 2,789.4       $ 1,765.5      

 
Fuel and purchased energy expenses:                                
  Mid-Atlantic Fleet   $ (789.9 )     $ (551.2 )     $ (420.9 )    
  Plants with Power Purchase Agreements     (51.9 )       (40.0 )       (13.9 )    
  Competitive Supply     (4,830.7 )       (583.8 )       (49.7 )    
  Other                          

 
  Total   $ (5,672.5 )     $ (1,175.0 )     $ (484.5 )    

 
Revenues less fuel and purchased energy expenses:

   
  % of Total
   
  % of Total
   
  % of Total
 
  Mid-Atlantic Fleet   $ 984.6   50 % $ 863.9   53 % $ 958.3   75 %
  Plants with Power Purchase Agreements     568.1   29     416.4   26     56.9   4  
  Competitive Supply     377.8   19     277.7   17     185.3   14  
  Other     45.1   2     56.4   4     80.5   7  

 
  Total   $ 1,975.6   100 % $ 1,614.4   100 % $ 1,281.0   100 %

 

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

Mid-Atlantic Fleet

 
  2003
  2002
  2001
 

 
 
  (In millions)
 
Revenues   $ 1,774.5   $ 1,415.1   $ 1,379.2  
Fuel and purchased energy expenses     (789.9 )   (551.2 )   (420.9 )

 
Revenues less fuel and purchased energy expenses   $ 984.6   $ 863.9   $ 958.3  

 

Revenues

We provide the changes in Mid-Atlantic Fleet revenues compared to the respective prior years in the following table:

 
  2003 vs. 2002

  2002 vs. 2001

 

 
 
  (In millions)
 
BGE's standard offer service   $ (61.2 ) $ (8.3 )
BGE Home electric sales     29.7     45.3  
Other     390.9     (1.1 )

 
Total increase   $ 359.4   $ 35.9  

 

        The decreases for both periods in BGE's standard offer service revenues were mostly due to approximately 1,200 MW of large commercial and industrial customers leaving BGE's standard offer service in the second quarter of 2002 and electing other electric generation suppliers. In 2002 compared to 2001, the decrease was partially offset by higher volumes sold due to warmer summer weather.

        Approximately one-third of the load for large commercial and industrial customers that left BGE's standard offer service elected BGE Home, a subsidiary of Constellation Energy, as their electric generation supplier. Our merchant energy business continues to provide the energy to BGE Home to meet the requirements of these customers under market-based rates. Beginning in the second quarter of 2003, as contracts for large commercial and industrial customers being served by BGE Home expire, the renewal of any customer will be with NewEnergy, our subsidiary which provides electric and gas energy services to commercial and industrial customers and which is included in our Competitive Supply category.

        Other Mid-Atlantic Fleet revenues increased $390.9 million during 2003 compared to 2002. The increase is primarily due to the following:

        Other Mid-Atlantic Fleet revenues were about the same in 2002 compared to 2001.

Fuel and Purchased Energy Expenses

Our merchant energy business had higher fuel and purchased energy expenses for the Mid-Atlantic Fleet in 2003 compared to 2002 primarily due to the following:

        Our merchant energy business had higher fuel and purchased energy expenses for the Mid-Atlantic Fleet in 2002 compared to 2001 primarily due to higher replacement power costs from the extended outage at Calvert Cliffs and higher coal prices. These were partially offset by lower generation at our coal plants.

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Plants with Power Purchase Agreements

 
  2003
  2002
  2001
 

 
 
  (In millions)
 
Revenues   $ 620.0   $ 456.4   $ 70.8  
Fuel and purchased energy expenses     (51.9 )   (40.0 )   (13.9 )

 
Revenues less fuel and purchased energy expenses   $ 568.1   $ 416.4   $ 56.9  

 

        The increases in revenues during 2003 compared to 2002 were primarily due to:

        Our plants with purchase power agreements had higher fuel and purchased energy expenses in 2003 due to the operation of High Desert and the Oleander facilities.

        The increases in revenues and expenses during 2002 compared to 2001 were primarily due to a full year's results from Nine Mile Point, which we acquired in November 2001, and the University Park generating facility, which commenced operations in the second half of 2001. In addition, the Oleander generating facility commenced operations in the second half of 2002.

Competitive Supply

 
  2003
  2002
  2001
 

 
 
  (In millions)
 
Accrual revenues   $ 5,157.1   $ 623.4   $ 59.2  
Mark-to-market revenues     51.4     238.1     175.8  
Fuel and purchased energy expenses     (4,830.7 )   (583.8 )   (49.7 )

 
Revenues less fuel and purchased energy expenses   $ 377.8   $ 277.7   $ 185.3  

 

We analyze our accrual and mark-to-market competitive supply activities separately below.

Accrual Revenues and Fuel and Purchased Energy Expenses

We provide the changes in revenues and fuel and purchased energy expenses in 2003 compared to 2002 and in 2002 compared to 2001 in the following table:

 
  2003 vs. 2002
   
   
 
  2002 vs. 2001
 
   
  Increases
in fuel and
purchased
energy
expenses

 
  Increases
in revenues

  Increases
in revenues

  Increases
in fuel and purchased
energy
expenses


 
  (In millions)
Wholesale accrual activities   $ 2,133.3   $ 1,912.6   $ 228.0   $ 238.2
Acquisitions     2,400.4     2,334.3     336.2     295.9

Total increase   $ 4,533.7   $ 4,246.9   $ 564.2   $ 534.1

        Our accrual revenues and fuel and purchased energy expenses increased in 2003 compared to 2002 mostly because of the re-designation of our load-serving activities to accrual, including the adoption of EITF 02-3, combined with increased wholesale accrual origination activities, primarily in Texas and New England, and the acquisitions of NewEnergy and Alliance. Our accrual revenues also increased due to additional product and service offerings, and includes approximately $33 million of pre-tax gains on contract restructurings. We discuss the implications of EITF 02-3 in more detail in the Critical Accounting Policies section and in Note 1.

        Our accrual revenues and fuel and purchased energy expenses increased in 2002 primarily due to the re-designation of our Texas and New England load-serving activities to accrual and the acquisition of NewEnergy in September 2002. We discuss the re-designation of Texas and New England below.

        Since February 2002, we manage our Texas load-serving activities as a physical delivery business separate from our trading activities and re-designated these activities as non-trading. We believe this designation more accurately reflects the substance of our Texas load-serving physical delivery activities.

        At the time of this change in designation, we reclassified the fair value of load-serving contracts and physically delivering power purchase agreements in Texas from "Mark-to-market energy assets and liabilities" to "Other assets and liabilities." The contracts reclassified consisted of gross assets of $78 million and gross liabilities of $15 million, or a net asset of $63 million. EITF 02-3 subsequently required us to remove the unamortized balance of these assets and liabilities, excluding the costs of any acquired contracts, from our Consolidated Balance Sheets on January 1, 2003.

        After the change in designation, the results of our Texas load-serving activities are included in "Nonregulated revenues" on a gross basis as power is delivered to our customers and "Operating expenses" as costs are incurred. Prior to the re-designation, the results of these activities were reported on a net basis as part of mark-to-market revenues included in "Nonregulated revenues." Mark-to-market revenues for the Texas trading activities were a net loss of $1.2 million for the portion of 2002 prior to designation as non-trading. Mark-to-market revenues for the Texas trading activities were a net loss of $33.4 million in 2001.

        Since future power sales revenues and costs from these activities are reflected in our Consolidated Statements of Income as part of "Nonregulated revenues" when power is delivered and "Operating expenses" when the costs are incurred, this re-designation generally delays the recognition of earnings from these activities compared to what we would have recognized under mark-to-market accounting. The change in designation of our Texas load-serving activities did not impact our cash flows.

        In addition, our New England load-serving activities consists primarily of contracts to serve the full energy and capacity requirements of retail customers and electric distribution utilities and associated power purchase agreements to supply our customers' requirements. We manage these activities primarily to assure profitable delivery of customers' energy requirements rather than as a traditional trading activity. Therefore, we use accrual accounting for New England load-serving transactions

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and associated power purchase agreements entered into since the second quarter of 2002.

        Because applicable accounting rules significantly limited the circumstances under which contracts previously designated as a trading activity could be re-designated as non-trading, prior to EITF 02-3, we were required to continue to include contracts entered into before the second quarter of 2002 in our mark-to-market accounting portfolio. However, under EITF 02-3, on January 1, 2003, we removed these contracts from our "Mark-to-market energy assets and liabilities" and began to account for these contracts under the accrual method of accounting.

Mark-to-Market Revenues

Mark-to-market revenues include net gains and losses from origination and risk management activities for which we use the mark-to-market method of accounting. We discuss these activities and the mark-to-market method of accounting in more detail in the Critical Accounting Policies section and in Note 1. We also discuss the implications of EITF 02-3 on the mark-to-market method of accounting in the Critical Accounting Policies section and in Note 1.

        As a result of the nature of our operations and the use of mark-to-market accounting for certain activities, mark-to-market 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 the Market Risk section. The primary factors that cause fluctuations in our mark-to-market revenues and earnings are:

        Mark-to-market revenues were as follows:

 
  2003
  2002
  2001
 

 
 
  (In millions)
 
Unrealized revenues                    
  Origination gains   $ 62.3   $ 160.4   $ 227.0  
  Risk management                    
    Unrealized changes in fair value     (10.9 )   66.9     (55.7 )
    Changes in valuation techniques         10.8     4.5  
    Reclassification of settled contracts to realized     (123.5 )   (45.4 )   (19.7 )

 
  Total risk management     (134.4 )   32.3     (70.9 )

 
Total unrealized revenues     (72.1 )   192.7     156.1  
Realized revenues     123.5     45.4     19.7  

 
Total mark-to-market revenues   $ 51.4   $ 238.1   $ 175.8  

 

        Origination gains arise from contracts that our wholesale marketing and risk management operation structure to meet the risk management needs of our customers. Transactions that result in origination gains may be unique and provide the potential for individually significant revenues and gains from a single transaction.

        Origination gains represent the initial fair value recognized on these structured transactions. The recognition of origination gains is dependent on the existence of observable market data that validates the initial fair value of the contract. For the year ending December 31, 2003, origination gains contributed $62.3 million before tax. Origination gains arose from 14 transactions completed in 2003, of which no transaction individually contributed in excess of $10 million pre-tax. The amount of 2003 origination gains decreased significantly as compared to 2002 due to the implementation of EITF 02-3.

        As noted above the recognition of origination gains is dependent on sufficient observable market data. Liquidity and market conditions impact our ability to identify sufficient, objective market-price information to permit recognition of origination gains. As a result, while our strategy and competitive position provide the opportunity to continue to originate such transactions, the level of origination revenue we are able to recognize may vary from year to year as a result of the number, size, and market-price transparency of the individual transactions executed in any period.

        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 mark-to-market revenues below. We show the relationship between our revenues and the change in our net mark-to-market energy asset later in this section.

        Our mark-to-market revenues were and continue to be affected by a decrease in the portion of our activities that is subject to mark-to-market accounting. As previously discussed in the Accrual Revenues and Fuel and Purchased Energy section, we re-designated our Texas load-serving activities as accrual during 2002, and we began to account for new non-derivative origination transactions on the accrual basis rather than under mark-to-market accounting. Beginning January 1, 2003, under EITF 02-3, we no longer record existing non-derivative contracts at fair value. Further, effective July 1, 2002, to the extent that we are not able to observe quoted market prices or other current market transactions for contract values determined using models, we record a reserve to adjust such contracts to result in zero gain or loss at inception. We remove the reserve and record such contracts at fair value when we obtain current market information for contracts with similar terms and counterparties.

        Mark-to-market revenues decreased $186.7 million in 2003 compared to 2002 mostly because of lower revenues from origination transactions, net losses from risk management activities compared to net gains in the prior year, and the reclassification of revenues from settled contracts to realized revenues. The lower level of origination transactions primarily reflects the continuing reduction of the portion of our activities subject to mark-to-market accounting. The decrease in risk management revenues is primarily due to mark-to-market revenue associated with the restructuring of our High Desert contract with the CDWR that had a positive impact in 2002, unfavorable changes in regional power prices, price volatility, and the impact of mark-to-market losses on economic hedges that did not qualify for hedge accounting treatment as discussed in more detail below.

        With the implementation of EITF 02-3 in the first quarter of 2003, all of our load-serving contracts were converted to accrual accounting. However, several economically effective hedges on these positions did not qualify for accrual accounting treatment under SFAS No. 133 and remained in the mark-to-market portfolio. In 2003, increasing forward prices shifted value between accrual load-serving positions and

39


associated mark-to-market hedges producing a timing difference in the recognition of earnings on related transactions. As a result, we recorded a $47.4 million pre-tax loss on the mark-to-market hedges during 2003. This mark-to-market loss will be offset by the end of 2006 as we realize the related accrual load-serving positions in cash.

        Mark-to-market revenues increased $62.3 million during 2002 compared to 2001 mostly because of net gains from risk management activities compared to net losses in the prior year, partially offset by lower revenues from origination transactions. The increase in risk management revenues is primarily due to the absence of mark-to-market losses recorded in 2001 on Texas trading activities designated as non-trading in 2002, favorable changes in regional power prices, price volatility, and other factors in 2002 compared to 2001. The decrease in origination revenues reflects the use of accrual accounting for new load-serving transactions originated beginning in the second quarter of 2002, the impact of applying the EITF 02-3 guidance on recording gains at the time of contract origination as previously described in the Critical Accounting Policies section, and fewer individually significant transactions in 2002 as compared to 2001.

Mark-to-Market Energy Assets and Liabilities

Our mark-to-market energy assets and liabilities are comprised of derivative contracts, and in 2002, prior to the implementation of EITF 02-3, were comprised of a combination of derivative and non-derivative (physical) contracts. The non-derivative assets and liabilities primarily related to load-serving activities originated prior to the shift to accrual accounting in 2002. While some of our mark-to-market 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. We discuss our modeling techniques later in this section.

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

At December 31,

  2003
  2002

 
  (In millions)
Current Assets   $ 555.2   $ 759.4
Noncurrent Assets     286.9     926.8

Total Assets     842.1     1,686.2


Current Liabilities

 

 

541.5

 

 

709.6
Noncurrent Liabilities     283.0     460.0

Total Liabilities     824.5     1,169.6

Net mark-to-market energy asset   $ 17.6   $ 516.6

        The following are the primary sources of the change in net mark-to-market energy asset during 2003 and 2002:

 
  2003
  2002
 

 
 
  (In millions)
 
Fair value beginning of year         $ 516.6         $ 418.4  
Changes in fair value recorded as revenues                          
  Origination gains   $ 62.3         $ 160.4        
  Unrealized changes in fair value     (10.9 )         66.9        
  Changes in valuation techniques               10.8        
  Reclassification of settled contracts to realized     (123.5 )         (45.4 )      
   
       
       
Total changes in fair value recorded as revenues           (72.1 )         192.7  
Cumulative effect impact of EITF 02-3           (379.4 )          
Contracts designated as normal purchases/sales and hedges upon implementation of EITF 02-3           (58.2 )          
Contract exchange           (68.9 )          
Changes in fair value recorded as operating expenses                     9.0  
Changes in value of exchange-listed futures and options           (8.4 )         (8.5 )
Net change in premiums on options           99.3           (40.1 )
Texas contracts re-designated as non-trading                     (63.3 )
Other changes in fair value           (11.3 )         8.4  

 
Fair value at end of year         $ 17.6         $ 516.6  

 

        Changes in the net mark-to-market energy asset that affected revenues were as follows:

        The net mark-to-market energy asset also changed due to the following items recorded in accounts other than revenue:

40


        We discuss our Texas contracts re-designated as non-trading in more detail in the Competitive Supply section.

        The settlement terms of our net mark-to-market energy asset and sources of fair value as of December 31, 2003 are as follows:

 
  Settlement Term
   
 
 
  Fair Value
 
 
  2004
  2005
  2006
  2007
  2008
  2009
  Thereafter
 

 
 
  (In millions)
 
Prices provided by external sources (1)   $ 13.2   $ (1.8 ) $ 76.4   $ (0.6 ) $   $   $   $ 87.2  
Prices based on models     0.5     (1.5 )   (73.8 )   12.4     (0.8 )   (2.6 )   (3.8 )   (69.6 )

 
Total net mark-to-market energy asset   $ 13.7   $ (3.3 ) $ 2.6   $ 11.8   $ (0.8 ) $ (2.6 ) $ (3.8 ) $ 17.6  

 
(1)
Includes contracts actively quoted and contracts valued from other external sources.

        We manage our mark-to-market risk on a portfolio basis based upon the delivery period of our 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 presented under the caption "prices provided by external sources." This 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 that 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 and simulation procedures. Inputs to the models include:

41


        Additionally, we incorporate counterparty-specific credit quality and factors for market price and volatility 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 we hold 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 commodities has not developed, the majority of contracts used in the wholesale marketing and risk management operation are direct contracts between market participants and are not exchange-traded or financially settling contracts that can be readily liquidated in their entirety through an exchange or other market mechanism. Consequently, we 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 wholesale marketing and risk management operation, 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, 2003 and could change significantly as a result of future changes in these factors. Additionally, because the depth and liquidity of the power markets vary substantially between regions and time periods, the prices used to determine fair value could be affected significantly by the volume of transactions executed.

        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, future market prices and actual quantities will vary from those used in recording mark-to-market energy assets and liabilities, and it is possible that such variations could be material.

Other

 
  2003
  2002
  2001

 
  (In millions)
Revenues   $ 45.1   $ 56.4   $ 80.5

        Our merchant energy business holds up to a 50% ownership interest in 25 operating domestic energy projects that consist of electric generation, fuel processing, or fuel handling facilities. Of these 25 projects, 18 are "qualifying facilities" that receive certain exemptions and pricing under the Public Utility Regulatory Policy Act of 1978 based on the facilities' energy source or the use of a cogeneration process. In addition, we own 100% of a geothermal generating facility in Hawaii. Earnings from our investments were $2.0 million in 2003, $9.1 million in 2002 and $23.1 million in 2001.

        The decrease in revenues in 2003 compared to 2002 was due to lower revenues from our California projects because we reversed certain credit reserves that totaled $9.1 million during the first quarter of 2002, as we began receiving payments from the California utilities, which had a positive impact in 2002, partially offset by a geothermal project generating at a higher capacity in 2003. The decrease in revenues in 2002 compared to 2001 was due to a geothermal project generating at a lower capacity and lower revenues from our California projects.

        At December 31, 2003, our investment in qualifying facilities and domestic power projects consisted of the following:

Book Value at December 31,
  2003
  2002

 
  (In millions)
Project Type            
  Coal   $ 130.5   $ 133.9
  Hydroelectric     57.3     62.6
  Geothermal*     56.0     151.4
  Biomass     51.4     52.6
  Fuel Processing     22.5     23.2
  Solar     10.5     10.5

Total   $ 328.2   $ 434.2

*  During 2003, we acquired the minority interest from our partner in a geothermal project and removed the equity-method investment in the project and consolidated the assets and liabilities of the project in our Consolidated Balance Sheets.

        We believe the current market conditions for our equity-method investments that own geothermal, coal, hydroelectric, and fuel processing projects provide sufficient positive cash flows to recover our investments. We continuously monitor issues that potentially could impact future profitability of these investments, including environmental and legislative initiatives. We discuss certain risks and uncertainties in more detail in our Forward Looking Statements section. However, should future events cause these investments to become uneconomic, our investments in these projects could become impaired under the provisions of APB No. 18.

        Currently, we are re-evaluating our strategy regarding our geothermal generating facility, which we obtained control by purchasing our partner's interest in December 2003. Upon obtaining control, we removed our equity-method investment and included the assets and liabilities in our Consolidated

42


Balance Sheets. As of December 31, 2003, this generating facility had property, plant and equipment with a net book value of approximately $137 million.

        The reevaluation of our strategy has included soliciting bids to determine the level of interest in the project, and if we determine that offers to purchase the project would provide more attractive cash flows than under our current hold and use strategy, we may decide to dispose of the project.

        While we have not completed the reevaluation of our strategy, based upon the number and level of bids received, management has determined that disposal of the project is more likely than not to occur. As a result, we evaluated our facility for impairment as of December 31, 2003, in accordance with SFAS No. 144, and determined that the assets were not impaired. We expect to complete the reevaluation of our strategy in the first half of 2004, and if we ultimately dispose of the plant, the actual proceeds received could be less than the carrying value of the plant resulting in a loss that could be material.

        The ability to recover our costs in our equity-method investments that own biomass and solar projects is partially dependent upon subsidies from the State of California. Under the California Public Utility Act, subsidies currently exist in that the California Public Utilities Commission (CPUC) requires electric corporations to identify a separate rate component to fund the development of renewable resources technologies, including solar, biomass, and wind facilities. In addition, recently enacted legislation in California requires that each electric corporation increase its total procurement of eligible renewable energy resources by at least one percent per year so that 20% of its retail sales are procured from eligible renewable energy resources by 2017. The legislation also requires the California Energy Commission to award supplemental energy payments to electric corporations to cover above-market costs of renewable energy.

        Given the need for electric power and the desire for renewable resource technologies, we believe California will continue to subsidize the use of renewable energy to make these projects economical to operate. However, should the California legislation fail to adequately support the renewable energy initiatives, our equity-method investments in these types of projects could become impaired under the provisions of APB No. 18, and any losses recognized could be material.

        If our strategy were to change from an intent to hold to an intent to sell for any of our equity-method investments in qualifying facilities or power projects, we would need to adjust their book value to fair value, and that adjustment could be material. If we were to sell these investments in the current market, we may have losses that could be material.

Operations and Maintenance Expenses

Our merchant energy business operations and maintenance expenses increased $183.5 million in 2003 compared to 2002 mostly due to the following:

        These increases were partially offset by cost reductions due to productivity initiatives including our corporate-wide workforce reduction programs.

        Our merchant energy business operations and maintenance expenses increased $189.6 million in 2002 compared to 2001 mostly due to the following:

        These increases were partially offset by the following:

Workforce Reduction Costs, Impairment Losses and Other Costs, Contract Termination Related Costs, and Net Loss on Sales of Assets

Our merchant energy business recognized expenses associated with our workforce reduction efforts, impairment losses and other costs, contract termination related costs, and a net loss on sales of assets as discussed in more detail in Note 2.

43


Depreciation and Amortization Expense

Merchant energy depreciation and amortization expense decreased $13.3 million in 2003 compared to 2002 mostly because of the adoption of SFAS No. 143.

        Under SFAS No. 143, a portion of the decommissioning amortization is included as "Accretion of asset retirement obligations" expense beginning in 2003 as discussed below. In addition, beginning in 2003 we no longer include the expected net future costs of removal as a component of depreciation expense. These decreases were partially offset by higher depreciation expense related to new generating facilities that commenced operations in mid-2002 and High Desert that commenced operations in 2003.

        Merchant energy depreciation and amortization expense increased $67.9 million in 2002 compared to 2001 mostly because of the depreciation and amortization associated with Nine Mile Point and the new generating facilities that commenced operations in mid-2002 and mid-2001.

Accretion of Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143 that requires the accretion of the asset retirement obligation liability due to the passage of time until the liability is settled. Accordingly, we recognized $42.7 million of accretion expense in 2003. We discuss SFAS No. 143 in Note 1.

Taxes Other Than Income Taxes

Merchant energy taxes other than income taxes increased $19.5 million in 2003 compared to 2002 mostly because of gross receipt taxes associated with NewEnergy and property taxes on new generating facilities.

        Merchant energy taxes other than income taxes increased $34.1 million in 2002 compared to 2001 mostly because of taxes other than income taxes associated with Nine Mile Point and the new generating facilities.


Regulated Electric Business

As discussed in the Electric Competition—Maryland section, our regulated electric business was significantly impacted by the July 1, 2000 implementation of customer choice.

        Effective July 1, 2000, BGE unbundled its rates to show separate components for delivery service, transition charges, standard offer service (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.

        As part of the deregulation of electric generation, while total rates were frozen over the transition period, the increasing rates received from customers under the standard offer service are offset by declining CTC rates.

Results

 
  2003
  2002
  2001
 

 
 
  (In millions)
 
Revenues   $ 1,921.6   $ 1,966.0   $ 2,040.0  
Electric fuel and purchased energy     (1,023.5 )   (1,080.7 )   (1,192.8 )
Operations and maintenance expenses     (297.4 )   (252.4 )   (258.7 )
Workforce reduction costs     (0.6 )   (34.0 )   (55.7 )
Depreciation and amortization     (181.7 )   (174.2 )   (173.3 )
Taxes other than income taxes     (137.9 )   (137.0 )   (139.5 )

 
Income from Operations   $ 280.5   $ 287.7   $ 220.0  

 
Net Income   $ 107.5   $ 99.3   $ 50.9  

 
Special Items Included in Operations (after-tax)  
  Workforce reduction costs   $ (0.4 ) $ (20.5 ) $ (33.6 )

 

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 the regulated electric business increased in 2003 compared to 2002 mostly because of:

        These favorable results were partially offset by distribution service restoration expenses related to Hurricane Isabel and other major storms in 2003. Total distribution service restoration expenses related to Hurricane Isabel were $22.2 million after-tax, which included $19.4 million after-tax of incremental expenses.

        Net income from the regulated electric business increased in 2002 compared to 2001 mostly because of the following:

44


Electric Revenues

The changes in electric revenues in 2003 and 2002 compared to the respective prior year were caused by:

 
  2003
  2002
 

 
 
  (In millions)
 
Distribution sales volumes   $ 3.0   $ 32.7  
Standard offer service     (54.2 )   (70.2 )
Fuel rate surcharge         (43.2 )

 
Total change in electric revenues from electric system sales     (51.2 )   (80.7 )
Other     6.8     6.7  

 
Total change in electric revenues   $ (44.4 ) $ (74.0 )

 

Distribution Sales Volumes

"Distribution sales volumes" are sales to customers in BGE's service territory at rates set by the Maryland PSC.

        The percentage changes in our electric system sales volumes, by type of customer, in 2003 and 2002 compared to the respective prior year were:

 
  2003
  2002
 

 
Residential   0.8 % 8.0 %
Commercial   2.1   3.2  
Industrial   (3.0 ) 0.7  

        In 2003, we distributed about the same amount of electricity to residential customers compared to 2002. We distributed more electricity to commercial customers mostly due to increased usage per customer. We distributed less electricity to industrial customers mostly due to lower usage by industrial customers.

        In 2002, we distributed more electricity to residential and commercial customers compared to 2001 due to warmer summer weather, increased usage per customer, and an increased number of customers. We distributed about the same amount of electricity to industrial customers in 2002 compared to 2001.

Standard Offer Service

BGE provides standard offer service for customers that do not select an alternative generation supplier as discussed in the Electric Competition—Maryland section.

        Standard offer service revenues decreased in 2003 compared to 2002 and decreased in 2002 compared to 2001 mostly because a majority of BGE's large commercial and industrial customers left standard offer service in the second quarter of 2002 and elected other electric generation suppliers. In 2003, these decreased revenues were partially offset by an increase in the standard offer service rate that BGE charges its customers. In 2002, these decreased revenues were partially offset by increased sales to residential customers mostly due to warmer summer weather and an increase in the standard offer service rate that BGE charges its customers.

        As a result of large commercial and industrial customers leaving BGE's standard offer service, BGE had lower purchased energy expense as discussed in the Electric Fuel and Purchased Energy Expenses section.

Electric Fuel and Purchased Energy Expenses

 
  2003
  2002
  2001

 
  (In millions)
Actual costs   $ 1,023.5   $ 1,080.7   $ 1,150.5
Recovery of costs deferred under electric fuel rate clause             42.3

Total electric fuel and purchased energy expenses   $ 1,023.5   $ 1,080.7   $ 1,192.8

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, our merchant energy business.

        BGE's actual costs of electricity purchased for resale expenses decreased in 2003 compared to 2002 and decreased in 2002 compared to 2001 mostly because large commercial and industrial customers left BGE's standard offer service and elected other electric generation suppliers as previously discussed in the Standard Offer Service section.

Electric Operations and Maintenance Expenses

Regulated electric operations and maintenance expenses increased $45.0 million in 2003 compared to 2002 mostly because of distribution service restoration expenses related to Hurricane Isabel of $36.8 million, which includes $4.7 million of non-incremental labor expenses, and distribution service restoration expenses related to other major storms. This increase also reflects higher benefit and inflationary costs, partially offset by lower uncollectible expenses and cost reductions resulting from our corporate-wide workforce reduction programs and other productivity initiatives.

        Regulated electric operations and maintenance expenses decreased $6.3 million in 2002 compared to 2001 mostly due to cost reductions resulting from our corporate-wide workforce reduction programs and other productivity initiatives.

Workforce Reduction Costs

BGE's electric business recognized expenses associated with our workforce reduction efforts as discussed in Note 2.

Electric Depreciation and Amortization Expense

Regulated electric depreciation and amortization expense increased in 2003 compared to 2002 mostly because of accelerated amortization associated with the planned replacement of information technology assets.

        Regulated electric depreciation and amortization expense was about the same during 2002 compared to 2001.

45



Regulated Gas Business

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.

Results

 
  2003
  2002
  2001
 

 
 
  (In millions)

 
Revenues   $ 726.0   $ 581.3   $ 680.7  
Gas purchased for resale expenses     (445.8 )   (316.7 )   (401.3 )
Operations and maintenance expenses     (98.0 )   (102.9 )   (104.3 )
Workforce reduction costs     (0.1 )   (1.3 )   (1.3 )
Depreciation and amortization     (46.6 )   (47.4 )   (47.7 )
Taxes other than income taxes     (31.0 )   (34.4 )   (34.3 )

 
Income from Operations   $ 104.5   $ 78.6   $ 91.8  

 
Net Income   $ 43.0   $ 31.1   $ 37.5  

 
Special Items Included in Operations (after-tax)  
  Workforce reduction costs   $ (0.1 ) $ (0.8 ) $ (0.8 )

 

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.

Net income from our regulated gas business increased during 2003 compared to 2002 mostly because of:

        Net income from our regulated gas business decreased during 2002 compared to 2001 mostly because of a $7.7 million pre-tax disallowed portion of a previously established regulatory asset as discussed in the Gas Cost Adjustments section and a $3.7 million pre-tax decrease in the shareholders' portion of the sharing mechanism under our gas cost adjustment clauses.

Gas Revenues

The changes in gas revenues in 2003 and 2002 compared to the respective prior year were caused by:

 
  2003
  2002
 

 
 
  (In millions)
 
Distribution sales volumes   $ 21.6   $ 1.4  
Base rates     (1.3 )   (2.9 )
Weather normalization     (18.9 )   (0.5 )
Gas cost adjustments     132.4     (55.8 )

 
Total change in gas revenues from gas system sales     133.8     (57.8 )
Off-system sales     10.0     (38.8 )
Other     0.9     (2.8 )

 
Total change in gas revenues   $ 144.7   $ (99.4 )

 

Distribution Sales Volumes

The percentage changes in our distribution sales volumes, by type of customer, in 2003 and 2002 compared to the respective prior year were:

 
  2003
  2002
 

 
Residential   13.8 % 3.5 %
Commercial   7.6   7.1  
Industrial   (21.5 ) (1.4 )

        We distributed more gas to residential and commercial customers during 2003 compared to 2002 mostly due to colder winter weather, an increased number of customers and increased usage per customer. We distributed less gas to industrial customers mostly due to decreased usage per customer.

        We distributed more gas to residential and commercial customers during 2002 compared to 2001 mostly due to increased usage per customer, slightly colder weather, and an increased number of customers. We distributed less gas to industrial customers mostly because of a decreased number of customers.

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 was about the same during 2003 as compared to 2002. The shareholders' portion decreased $3.7 million during 2002 compared to 2001.

        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.

        Delivery service customers 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 distributed and are included in gas distribution sales volumes.

46


        Gas cost adjustment revenues increased during 2003 as compared to 2002 because we sold more gas at a higher price. Gas cost adjustment revenues decreased during 2002 compared to 2001 mostly because the gas we sold to non-delivery service customers was at a lower price, partially offset by more gas sold.

        In December 2002, a Hearing Examiner from the Maryland PSC issued a proposed order disallowing $7.7 million of a previously established regulatory asset for certain credits that were over-refunded to customers through our market-based rates. BGE reserved the $7.7 million of disallowed fuel costs in the fourth quarter of 2002. In August 2003, the Maryland PSC issued an order authorizing us to recover the $7.7 million and we reinstated the regulatory asset.

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). Changes in off-system sales do not significantly impact earnings.

        Revenues from off-system gas sales increased during 2003 compared to 2002 because we sold gas at a higher price, partially offset by less gas sold.

        Revenues from off-system gas sales decreased during 2002 compared to 2001 because we sold less gas at a lower price.

Gas Purchased For Resale Expenses

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

        Gas costs increased during 2003 as compared to 2002 mostly because we purchased more gas at a higher price.

        Gas costs decreased during 2002 compared to 2001 because we purchased gas at a lower price partially offset by the $7.7 million of disallowed fuel costs as previously discussed in the Gas Cost Adjustments section.

Gas Operations and Maintenance Expenses

Regulated gas operations and maintenance expenses decreased $4.9 million during 2003 as compared to 2002 mostly because of lower uncollectible expenses and cost reductions resulting from our corporate-wide workforce reduction programs and other productivity initiatives.

        Regulated gas operations and maintenance expenses were about the same during 2002 compared to 2001. In 2002, cost reductions resulting from our corporate-wide workforce reduction programs and other productivity initiatives were offset by the amortization of gas regulatory assets established in 2001 related to these initiatives.

Workforce Reduction Costs

BGE's gas business recognized expenses associated with our workforce reduction efforts as discussed in Note 2.


Other Nonregulated Businesses

Results

 
  2003
  2002
  2001
 

 
 
  (In millions)
 
Revenues   $ 587.9   $ 537.4   $ 552.6  
Operating expenses     (535.8 )   (505.9 )   (510.7 )
Workforce reduction costs     (0.1 )   (1.0 )   (2.7 )
Impairment losses and other costs     (0.6 )   (10.8 )   (111.9 )
Depreciation and amortization     (21.2 )   (16.6 )   (23.2 )
Taxes other than income taxes     (3.4 )   (4.3 )   (3.4 )
Net gain on sales of investments and other assets     26.2     265.0     6.2  

 
Income (Loss) from Operations   $ 53.0   $ 263.8   $ (93.1 )

 
Net Income (Loss) Before Cumulative Effect of Change in Accounting Principle     12.2   $ 148.0   $ (99.1 )
Cumulative Effect of Change in Accounting Principle             8.5  

 
Net Income (Loss)   $ 12.2   $ 148.0   $ (90.6 )

 
Special Items Included In Operations (after-tax)  
  Net gain on sales of investments and other assets   $ 16.4   $ 169.1   $ 1.9  
  Impairment of real estate, senior-living, and other investments     (0.4 )   (1.2 )   (72.5 )
  Workforce reduction costs     (0.1 )   (0.7 )   (1.7 )
  Costs associated with exit of BGE Home merchandise stores         (6.1 )    

 
Total Special Items   $ 15.9   $ 161.1   $ (72.3 )

 

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 $135.8 million during 2003 compared to 2002 mostly because we recognized a $163.3 million after-tax gain on the sale of our investment in Orion in 2002 that had a positive impact in that period. This decrease was partially offset by the following 2003 transactions:

47


        Net income from our other nonregulated businesses increased $238.6 million during 2002 compared to 2001 mostly because of the following:

        These increases were partially offset by the following:

        We discuss our special items further in Note 2.

        In addition, we recognized an $8.5 million after-tax, or $0.05 per share, gain for the cumulative effect of adopting SFAS No. 133 in the first quarter of 2001.

        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 included 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. In 2002, we sold approximately 800 acres of land holdings, all of our senior-living facilities, and a South American generating facility.

        At December 31, 2003, our remaining land holdings total approximately 220 acres. 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.

        In addition, we initiated a liquidation program for our financial investments operation. Through December 31, 2003, we have liquidated approximately 90% of our investment portfolio.

        While our intent is to dispose of these remaining non-core assets, market conditions and other events beyond our control may affect the actual sale of these assets. In addition, a future decline in the fair value of these assets could result in additional losses.


Consolidated Nonoperating Income and Expenses

Other Income

Other income decreased $11.4 million during 2003 compared to 2002 mostly because of lower interest income on temporary cash investments and higher earnings from consolidated investments where our ownership is less than 100%, which resulted in increased minority interest expense. Other income increased $29.2 million during 2002 compared to 2001 mostly because of interest income on the nuclear decommissioning trust fund transferred in connection with the acquisition of Nine Mile Point and income on temporary cash investments.

        Other income for BGE decreased $16.1 million in 2003 as compared to 2002 mostly because of an increase in charitable contributions and because of lower interest income on temporary cash investments in the Constellation Energy cash pool. Other income for BGE increased $10.3 million during 2002 compared to 2001 mostly because of interest income on temporary cash investments in the Constellation Energy cash pool.

Fixed Charges

Total fixed charges increased $58.7 million during 2003 compared to 2002 mostly because we had lower capitalized interest due to our new generating facilities commencing operations and a higher level of debt outstanding, including the issuance of $550 million of debt in June 2003 that was used to refinance the High Desert Power Project lease.

        Total fixed charges increased $42.7 million during 2002 compared to 2001 mostly because of a higher level of debt outstanding at higher interest rates and lower capitalized interest due to our new generating facilities commencing operations. In 2002, we issued $2.5 billion of long-term debt and used the proceeds to repay short-term borrowings, to prepay the Nine Mile Point sellers' note, and to fund acquisitions.

        Total fixed charges for BGE decreased $29.4 million during 2003 compared to 2002 mostly because of a lower level of debt outstanding and lower interest rates. Total fixed charges for BGE decreased $14.0 million during 2002 as compared to 2001 mostly because of a lower level of debt outstanding due to the repayment of maturing long-term debt.

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 Note 10.

Pension Expense

Our actual return on our qualified pension plan assets was 23% for the year ended December 31, 2003. We assume an expected return on pension plan assets of 9% for the purpose of computing annual net periodic pension expense in accordance with SFAS No. 87, Employers' Accounting for Pensions. Differences between actual and expected returns are deferred along with other actuarial gains and losses and reflected in future net periodic pension expense in accordance with SFAS No. 87. Expected and actual returns on pension assets also are affected by plan contributions.

        In 2003, we contributed $115 million to our pension plans. As of the date of this report, we contributed an additional $50 million to our pension plans in 2004. At December 31, 2003, we recorded an after-tax increase to equity of $12.6 million as a result of decreasing our additional minimum pension liability. We discuss our pension plans in more detail in Note 7.

48



Financial Condition

Cash Flows

The following table summarizes our 2003 cash flows by business segment, as well as our consolidated cash flows for 2003, 2002, and 2001. This table excludes the impact of the refinancing of the High Desert Power Project and the impact of changes in intercompany balances. We exclude the impact of the High Desert refinancing due to the fact that there was no net impact on cash. The financing source of cash we received from the issuance of debt was offset by the investing use of cash we incurred from terminating the lease. We discuss the refinancing of High Desert in more detail in the Significant Events of 2003 section and in Note 15.

 
  2003 Segment Cash Flows
  Consolidated Cash Flows
 
 
  Merchant
  Regulated
  Other
  2003
  2002
  2001
 

 
 
  (In millions)

 
Operating Activities                                      
  Net Income   $ 114.6   $ 150.5   $ 12.2   $ 277.3   $ 525.6   $ 90.9  
  Non-cash adjustments to net income     687.6     278.3     (18.1 )   947.8     606.0     749.9  
  Changes in working capital     (10.9 )   3.5     (57.9 )   (65.3 )   49.0     (288.4 )
  Pension and postemployment benefits*                       (69.4 )   (116.2 )   55.3  
  Other     (75.3 )   8.1     56.9     (10.3 )   (44.4 )   (34.4 )

 
Net cash provided by (used in) operating activities     716.0     440.4     (6.9 )   1,080.1     1,020.0     573.3  

 
Investing activities (excluding $514.1 million related to the refinancing of the High Desert lease)                                      
  Investments in property, plant and equipment     (333.3 )   (291.3 )   (33.4 )   (658.0 )   (831.9 )   (1,302.5 )
  Acquisitions, net of cash acquired (excluding High Desert)     (32.5 )           (32.5 )   (221.4 )   (382.7 )
  Contributions to nuclear decommissioning trust funds     (13.2 )           (13.2 )   (17.6 )   (22.0 )
  Sale of investments and other assets     1.3         147.5     148.8     838.0     287.1  
  Other investments     (86.1 )   1.8     (29.3 )   (113.6 )   (86.9 )   (52.6 )

 
Net cash (used in) provided by investing activities (excluding High Desert)     (463.8 )   (289.5 )   84.8     (668.5 )   (319.8 )   (1,472.7 )

 
Cash flows from operating activities less cash flows from investing activities   $ 252.2   $ 150.9   $ 77.9     411.6     700.2     (899.4 )
   
 
 
Financing Activities (excluding $514.1 million related to the refinancing of the High Desert lease)                                      
  Net repayment of debt (excluding High Desert)*                       (239.2 )   (62.9 )   396.4  
  Proceeds from issuance of common stock*                       95.4     28.5     504.4  
  Common stock dividends paid*                       (169.2 )   (137.8 )   (120.7 )
  Other*                       7.7     14.6     9.0  

                   
 
Net cash (used in) provided by financing activities (excluding High Desert)                       (305.3 )   (157.6 )   789.1  

                   
 
Net Increase (Decrease) in Cash and Cash Equivalents                     $ 106.3   $ 542.6   $ (110.3 )

                   
 

*Items are not allocated to the business segments because they are managed for the company as a whole.

Overview—2003 Compared to 2002

Cash flows from operating activities less cash flows from investing activities were $411.6 million in 2003 compared to $700.2 million in 2002. This decrease was primarily due to a reduction in proceeds from the sale of non-core assets of $689.2 million in 2003 compared to 2002. We discuss our sales of Orion and COPT in Note 2.

        Excluding the impact of these non-core asset sales, cash flows from operating activities less cash flows from investing activities were as follows:

 
  2003
  2002
  Change
 

 
 
  (In millions)

 
Cash flows from operating activities less cash flows from investing activities   $ 411.6   $ 700.2   $ (288.6 )
Less: cash flows from sale of investments and other assets     (148.8 )   (838.0 )   689.2  

 
Net   $ 262.8   $ (137.8 ) $ 400.6  

 

        The $400.6 million increase in 2003 compared to 2002 was primarily due to lower investments in property, plant and equipment of $173.9 million, lower cash used for acquisitions, excluding High Desert, of $188.9 million, and an increase in cash provided by operating activities of $60.1 million.

49


Cash Flows from Operating Activities

Cash provided by operating activities was $1,080.1 million in 2003 compared to $1,020.0 million in 2002 and $573.3 million in 2001. Non-cash adjustments to net income were $341.8 million higher in 2003 compared to 2002. The increase in non-cash adjustments to net income was primarily due to the following:

        These increases in non-cash adjustments to net income were offset in part by lower accruals for workforce reduction costs of $60.7 million in 2003 compared to 2002.

        Changes in working capital had a negative impact of $65.3 million on cash flow from operations in 2003 compared to a positive impact of $49.0 million in 2002. The $114.3 million decrease was primarily due to the following uses of cash in 2003 compared to 2002:

        These items were partially offset by a source of cash in 2003 compared to 2002 due to an increase in accrued income taxes.

        The increase in cash provided by operating activities in 2002 compared to 2001 was primarily due to higher net income and favorable changes in working capital.

Cash Flows from Investing Activities

Cash used in investing activities was $668.5 million in 2003, excluding the impact of the acquisition of the High Desert Power Project in 2003, compared to $319.8 million in 2002 and $1,472.7 million in 2001. The increase in cash used in 2003 compared to 2002 was primarily due to a decrease in cash proceeds from the sales of investments and other assets in 2003 because of the sale of Orion and COPT that generated $555.4 million in 2002. We discuss our sales of Orion and COPT in Note 2. These sales were partially offset by lower cash used for acquisitions in 2003 compared to 2002.

        The decrease in cash used in investing activities in 2002 compared to 2001 was mostly due to cash proceeds from the sale of non-core assets and a decrease in capital spending due to the termination of all planned development projects.

Cash Flows from Financing Activities

Cash used in financing activities was $305.3 million in 2003, excluding the impact of refinancing the High Desert Power Project, compared to $157.6 million in 2002. The decrease in 2003 compared to 2002 was mostly due a higher repayment of debt in 2003 compared to 2002.

        Cash provided by financing activities decreased $946.7 million in 2002 compared to 2001 mostly due to the issuance of common stock in 2001 and higher repayment of debt in 2002, partially offset by higher issuance of debt during 2002.


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, but are not limited to, cash flows, liquidity, and the amount of debt as a component of total capitalization. All Constellation Energy and BGE credit 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 Preferred Securities   BBB   A3   A-
  Preference Stock   BBB1   Baa1   A-

50



Available Sources of Funding

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.

Constellation Energy

In addition to our cash balance, we have a commercial paper program under which we can issue short-term notes to fund our subsidiaries. At December 31, 2003, we had approximately $1.5 billion of credit under three facilities as discussed below.

        In June 2003, Constellation Energy arranged a $447.5 million 364-day revolving credit facility and a $447.5 million three-year revolving credit facility replacing a maturing $640 million 364-day revolving credit facility and a maturing $188.5 million three-year revolving credit facility. We also have an existing $640 million revolving credit facility that expires in June 2005. We use these facilities to allow the issuance of commercial paper. In addition, we use the multi-year facilities to allow for the issuance of letters of credit.

        These revolving credit facilities allow the issuance of letters of credit up to approximately $1.1 billion.

        At December 31, 2003, letters of credit that totaled $507.1 million were issued under all of our facilities, which results in approximately $1.0 billion of unused credit facilities.

BGE

BGE maintains $200.0 million in annual committed credit facilities, expiring May through November 2004, in order to allow commercial paper to be issued. As of December 31, 2003, BGE had no outstanding commercial paper, which results in $200.0 million in unused credit facilities.

Other Nonregulated Businesses

BGE Home Products & Services maintains a program to sell up to $50 million of receivables. We expect to extend this program beyond the current expiration date in March 2004.

        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 actual consolidated capital requirements for the years 2001 through 2003, along with the estimated annual amount for 2004, are shown in the table below.

        We will continue to have cash requirements for:

        Capital requirements for 2004 and 2005 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.

 
  2001
  2002
  2003
  2004

 
  (In millions)

Nonregulated Capital Requirements:                        
  Merchant energy (excludes acquisitions)                        
    Construction program   $ 697   $ 122   $      
    Steam generators     53     83     59      
    Reactor vessel head replacement             8      
    Environmental controls     89     66     12      
    Continuing requirements (including nuclear fuel)     205     370     340 (A)    

     
  Total merchant energy capital requirements     1,044     641     419   $ 445
  Other nonregulated capital requirements     35     65     53     40

  Total nonregulated capital requirements     1,079     706     472     485

Utility Capital Requirements:                        
  Regulated electric     180     167     236     215
  Regulated gas     59     50     53     60

  Total utility capital requirements     239     217     289     275

Total capital requirements   $ 1,318   $ 923   $ 761   $ 760

(A)
The table above does not include the capital requirements and financing costs of approximately $40 million for the High Desert Power Project for the six months ended June 30, 2003. We discuss the acquisition of the High Desert Power Project in Note 15.

        As of the date of this report, we have not completed our 2005 capital budgeting process, but expect our 2005 capital requirements to be approximately $650-750 million.

51



Capital Requirements

Merchant Energy Business

Our merchant energy business' capital requirements consist of its continuing requirements, including construction expenditures for improvements to generating plants, nuclear fuel costs, costs of complying with the Environmental Protection Agency (EPA), Maryland, and Pennsylvania nitrogen oxides (NOx) emissions regulations, and enhancements to our information technology infrastructure. We discuss the NOx regulations and timing of expenditures in Note 12.

Regulated Electric and Gas

Regulated electric and gas construction expenditures primarily include new business construction needs and improvements to existing facilities, including projects to improve reliability. Capital requirements for 2003 in the table on the previous page include $32.0 million in costs incurred as a result of Hurricane Isabel to restore the electric distribution system.


Funding for Capital Requirements

Merchant Energy Business

Funding for the expansion of our merchant energy business is expected from internally generated funds. We also have available sources from commercial paper issuances, issuances of long-term debt and equity, leases, and other financing activities.

        The projects that our merchant energy business develops typically require substantial capital investment. Most of the projects recently constructed were funded through corporate borrowings by Constellation Energy. Many of the qualifying facilities and independent power projects that we have an interest in 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.

        We expect to fund acquisitions, including Ginna, with a mixture of debt and equity with an overall goal of maintaining a strong investment grade credit profile. Funding for this acquisition is expected to occur during 2004.

BGE

Funding for utility capital expenditures is expected from internally generated funds. During 2004, we expect our regulated utility business to generate sufficient cash flows from operations to meet BGE's operating requirements. If necessary, additional funding may be obtained from commercial paper issuances, available capacity under credit facilities, the issuance of long-term debt, trust preferred securities, or preference stock, and/or from time to time equity contributions from Constellation Energy. BGE also participates in a cash pool administered by Constellation Energy as discussed in Note 16.

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, sales of securities and assets, and/or from time to time equity contributions from Constellation Energy. BGE Home Products & Services can continue to fund capital requirements through sales of receivables.

        Our ability to sell or liquidate securities and non-core assets will depend on market conditions, and we cannot give assurances that these sales or liquidations could be made. We discuss our remaining non-core assets and market conditions in the Results of Operations—Other Nonregulated Businesses section.

Contractual Payment Obligations and Committed Amounts

We enter into various agreements that result in contractual payment obligations in connection with our business activities. These obligations primarily relate to our financing arrangements (such as long-term debt, preference stock, and operating leases), purchases of capacity and energy to support the growth in our merchant energy business activities, and purchases of fuel and transportation to satisfy the fuel requirements of our power generating facilities.

        Our total contractual payment obligations as presented in the table on the next page increased $7.2 billion during 2003 compared to 2002 primarily due to:

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        Our total contractual payment obligations as of December 31, 2003 are shown in the following table:

 
  Payments
 
  2004

  2005-
2006

  2007-
2008

  Thereafter

  Total


 
  (In millions)
Contractual Payment Obligations                              
  Long-term debt:1                              
    Nonregulated                              
      Principal   $ 12.6   $ 327.6   $ 654.1   $ 2,744.9   $ 3,739.2
      Interest     238.3     439.7     369.5     1,748.9     2,796.4

    Total     250.9     767.3     1,023.6     4,493.8     6,535.6
    BGE                              
      Principal     151.4     482.7     418.5     600.8     1,653.4
      Interest     90.1     169.4     96.7     824.0     1,180.2

    Total     241.5     652.1     515.2     1,424.8     2,833.6
  BGE preference stock                 190.0     190.0
  Operating leases     22.1     38.8     26.6     117.2     204.7
  Purchase obligations:2                              
    Purchased capacity and energy3     1,318.8     1,105.7     267.3     188.9     2,880.7
    Fuel and transportation4     551.8     424.6     63.9     52.8     1,093.1
    Other     76.7     48.8     40.7     218.9     385.1
  Other noncurrent liabilities:                              
    Postretirement and postemployment benefits5     39.0     87.0     99.5     136.3     361.8
    Other     2.6     2.7     1.6         6.9

Total contractual payment obligations   $ 2,503.4   $ 3,127.0   $ 2,038.4   $ 6,822.7   $ 14,491.5

1   Amounts in long-term debt reflect the original maturity date. Investors may require us to repay $387.0 million early through put options and remarketing features.
2   Contracts to purchase goods or services that specify all significant terms. Amounts related to certain purchase obligations are based on future purchase expectations which may differ from actual purchases.
3   Our contractual obligations for purchased capacity and energy are shown on a gross basis for certain transactions, including both the fixed payment portions of tolling contracts and estimated variable payments under unit-contingent power purchase agreements. We have recorded $34.2 million of liabilities related to purchased capacity and energy obligations at December 31, 2003 in our Consolidated Balance Sheets.
4   We have recorded liabilities of $78.5 million related to fuel and transportation obligations at December 31, 2003 in our Consolidated Balance Sheets.
5   Amounts related to postretirement and postemployment benefits are for unfunded plans and reflect present value amounts consistent with the determination of the related liabilities recorded on the Consolidated Balance Sheets as discussed in Note 7.

         The table below presents our contingent obligations. Our contingent obligations increased $1.8 billion during 2003, primarily due to the issuance of additional letters of credit and guarantees by the parent company of subsidiary obligations to third parties in support of the growth of our merchant energy business. These amounts do not represent incremental consolidated Constellation Energy obligations; rather, they primarily represent parental guarantees of certain subsidiary obligations to third parties. Our calculation of the fair value of subsidiary obligations covered by the $3,975.4 million of parent company guarantees was $902.2 million at December 31, 2003. Accordingly, if the parent company was required to fund subsidiary obligations, the total amount at current market prices is $902.2 million.

 
  Expiration
 
  2004

  2005-
2006

  2007-
2008

  Thereafter

  Total


 
  (In millions)

Contingent Obligations                              
  Letters of credit   $ 506.5   $ 0.6   $   $   $ 507.1
  Guarantees - competitive supply1     3,166.0     265.6     162.0     381.8     3,975.4
  Other guarantees, net2     16.1     9.9     10.6     483.0     519.6

Total contingent obligations   $ 3,688.6   $ 276.1   $ 172.6   $ 864.8   $ 5,002.1

1   While the face amount of these guarantees is $3,975.4 million, we do not expect to fund the full amount. Our calculation of the fair value of obligations covered by these guarantees was $902.2 million at December 31, 2003.
2   Other guarantees in the above table are shown net of liabilities of $25.6 million recorded at December 31, 2003 in our Consolidated Balance Sheets.

Liquidity Provisions

We have certain agreements that contain provisions that would require additional collateral upon significant credit rating decreases in the Senior Unsecured Debt of Constellation Energy. Decreases in Constellation Energy's credit ratings would not trigger an early payment on any of our credit facilities. However, under counterparty contracts related to our wholesale marketing and risk management operation, where we are obligated to post collateral, we estimate that we would have additional collateral obligations based on downgrades to the following credit ratings for our Senior Unsecured Debt:

Credit Ratings
Downgraded

  Level Below
Current
Rating

  Incremental
Obligations

  Cumulative
Obligations

 
   
  (In millions)
BBB/Baa2   1   $ 55   $ 55
BBB-/Baa3   2     135     190
Below investment grade   3     647     837

        At December 31, 2003, we had approximately $1.2 billion of unused credit facilities and $721.3 million of cash available to meet potential requirements. However, based on market conditions and contractual obligations at the time of such a downgrade, we could be required to post collateral in an amount that could exceed the amounts specified above, and which could be material.

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        In many cases, customers of our merchant energy business 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 to make new advances or issuing new letters of credit, but cannot accelerate existing amounts outstanding. The long-term debt indentures of Constellation Energy and BGE do not contain material adverse change clauses or financial covenants.

        Certain credit facilities of Constellation Energy contain a provision requiring Constellation Energy to maintain a ratio of debt to capitalization equal to or less than 65%. At December 31, 2003, the debt to capitalization ratios as defined in the credit agreements were no greater than 55%.

        Certain credit agreements of BGE contain provisions requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At December 31, 2003, the debt to capitalization ratio for BGE as defined in these credit agreements was 50%. At December 31, 2003, no amount is outstanding under these agreements.

        Failure by Constellation Energy, or BGE, to comply with these covenants could result in the maturity of the debt outstanding under these facilities being accelerated. The credit facilities of Constellation Energy contain usual and customary cross-default provisions that apply to defaults on debt by Constellation Energy and certain subsidiaries over a specified threshold. Certain BGE credit facilities also contain usual and customary cross-default provisions that apply to defaults on debt by BGE over a specified threshold. The indentures pursuant to which BGE has issued and outstanding mortgage bonds and subordinated debentures provide that a default under any debt instrument issued under the relevant indenture may cause a default of all debt outstanding under such indenture.

        Constellation Energy also 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 credit facilities in Note 8, long-term debt in Note 9, lease requirements in Note 11, and commitments and guarantees in Note 12.

Off-Balance Sheet Arrangements

For financing and other business purposes, we utilize certain off-balance sheet arrangements that are not reflected in our Consolidated Balance Sheets. Such arrangements do not represent a significant part of our activities or a significant ongoing source of financing. We use these arrangements when they enable us to obtain financing or execute commercial transactions on favorable terms. As of December 31, 2003, we have no material off-balance sheet arrangements including:

        We discuss our guarantees in Note 12.




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. 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

 
  2004
  2005
  2006
  2007
  2008
  Thereafter
  Total
  Fair value at
Dec. 31, 2003


 
  (Dollar amounts in millions)
Short-term debt                                                
Variable-rate debt   $ 9.6   $   $   $   $   $   $ 9.6   $ 9.6
Average interest rate     3.11 %                       3.11 %    
Long-term debt                                                
Variable-rate debt   $ 15.0   $ 12.8   $ 102.0   $ 10.1   $ 10.5   $ 172.8   $ 323.2   $ 323.2
Average interest rate     3.61 %   3.74 %   1.59 %   5.50 %   5.72 %   1.48 %   1.96 %    
Fixed-rate debt   $ 149.0 (A) $ 343.0   $ 352.5   $ 729.5   $ 322.5   $ 3,172.9   $ 5,069.4   $ 5,723.5
Average interest rate     5.70 %   7.71 %   5.53 %   6.54 %   5.82 %   6.33 %   6.38 %    
(A)
Amount excludes $387.0 million of long-term debt that contains certain put options under which lenders could potentially require us to repay the debt prior to maturity of which $179.2 million is classified as current portion of long-term debt in our Consolidated Balance Sheets and in our Consolidated Statements of Capitalization.

54


Commodity Risk

We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, and other commodities. These risks arise from our ownership and operation of power plants, the load-serving activities of BGE standard offer service and our competitive supply activities, and our mark-to-market origination and risk management activities. We discuss these risks separately for our merchant energy and our regulated businesses below.

Merchant Energy Business

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

Commodity Prices

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 and foreign exchange rates. A number of factors associated with the structure and operation of the energy markets significantly influence the level and volatility of prices for energy commodities and related derivative products. We use such commodities and contracts in our merchant energy business, and if we do not properly hedge the associated financial exposure, this commodity price volatility could affect our earnings. 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:

        As a result of declines in BGE's standard offer service load and approximately 3,800 MW of natural gas-fired peaking and combined cycle generating facilities placed in service between 2001 and 2003, we have an amount of generating capacity that is subject to future changes in wholesale electricity prices. Additionally, we have 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 or in the same direction as changes in fuel costs.

Supply and Demand Risk

We are exposed to the risk that available sources of supply may differ from the amount of power demanded by our customers under fixed-price load-serving contracts. During periods of high demand, our power supplies may be insufficient to serve our customers' needs and could require us to purchase additional energy at higher prices. Alternatively, during periods of low demand, our power supplies may exceed our customers' needs and could result in us selling that excess energy at lower prices. Either of those circumstances could have a negative impact on our earnings.

Operations Risk

Operations risk is the risk that a generating plant will not be available to produce energy and the risks related to physical delivery of energy to meet our customers' needs. For 2004, 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 serve the load requirements of the sellers of Nine Mile Point.

        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.

        Our nuclear plants produce electricity at a relatively low marginal 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.

Risk Management

As part of our overall portfolio, we manage the commodity price risk of our competitive supply activities and our electric generation facilities, including power sales, fuel and energy purchases, emission credits, weather risk, and the market risk of outages. In order to manage these risks, 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 and energy, including:

55


        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.

        While some of the contracts we use to manage risk 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. We use our best estimates to determine the fair value of commodity and derivative contracts we hold and sell. 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.

        We monitor and manage our risk exposures through separate, but complementary financial, operational, risk, and credit reporting systems. Constellation Energy's board of directors establishes parameters for the risks that we can undertake and risk levels are monitored daily by management and our Chief Risk Officer. In addition, we maintain segregation of duties with credit review and risk monitoring functions performed by groups that are independent from revenue producing groups.

        We measure the sensitivity of our wholesale marketing and risk management mark-to-market energy contracts to potential changes in market prices using value at risk. Value at risk is a statistical model that attempts to predict risk of loss based on historical market price volatility. We calculate value at risk using a variance/covariance technique that models option positions using a linear approximation of their value. Additionally, we estimate variances and correlation using historical commodity price changes over the most recent rolling three-month period. Our value at risk calculation includes all wholesale marketing and risk management 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 calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and our competitive supply load-serving activities. We manage these risks by monitoring our fuel and energy purchase requirements and our estimated contract sales volumes compared to associated supply arrangements. We also engage in hedging activities to manage these risks. We describe those risks and our hedging activities earlier in this section.

        The value at risk amount represents the potential pre-tax loss in the fair value of our wholesale marketing and risk management mark-to-market energy assets and liabilities over one and ten-day holding periods. Our value at risk for 2003 and 2002 were as follows:

For the year ended December 31,

  2003
  2002

 
  (In millions)

99% Confidence Level, One-Day Holding Period            
  Year end   $ 3.7   $ 4.8
  Average     6.6     10.0
  High     13.3     21.7
  Low     2.7     2.7

95% Confidence Level, One-Day Holding Period

 

 

 

 

 

 
  Year end   $ 2.8   $ 3.6
  Average     5.0     7.6
  High     10.1     16.6
  Low     2.1     2.1

95% Confidence Level, Ten-Day Holding Period

 

 

 

 

 

 
  Year end   $ 8.8   $ 11.4
  Average     15.9     24.1
  High     32.0     52.4
  Low     6.5     6.5

        Based on a 99% confidence interval, we would expect a one-day change in the fair value of the portfolio greater than or equal to the daily value at risk approximately once in every 100 days. In 2003, we experienced five instances where the actual daily mark-to-market change in portfolio value exceeded the predicted value at risk. This is primarily attributable to higher volatility of power and fuel prices experienced during 2003. On average, we expect to experience a change in value to our portfolio greater than our value at risk approximately 3 times in a calendar year. However, published market studies conclude that exceeding daily value at risk less than 7 times in a one-year period is considered consistent with a 99% confidence interval.

        The table above is the value at risk associated with our wholesale marketing and risk management operation's mark-to-market energy assets and liabilities, including both trading and non-trading activities. The following table details our value at risk for the trading portion of our wholesale marketing and risk management mark-to-market energy assets and liabilities over a one-day holding period at a 99% confidence level for 2003 and 2002:

At December 31,

  2003

  2002


 
  (In millions)

Average   $ 4.6   $ 3.6
High     10.9     15.4

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        Due to the inherent limitations of statistical measures such as value at risk 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.

Regulated Electric Business

Effective July 1, 2000, BGE's residential base rates are frozen for a six year period, and its commercial and industrial base rates are frozen for a four year period. The generation and transmission components of rates are frozen for different time periods depending on the service options selected by those customers. We discuss the impact on base rates beyond 2004 in the Electric Competition—Maryland section. Our wholesale marketing and risk management operation provides BGE with 100% of the energy and capacity required to meet its commercial and industrial standard offer service obligations through June 30, 2004, and 100% of the energy and capacity to meet its residential standard offer service obligations through June 30, 2006. BGE will obtain its supply for standard offer service to its commercial and industrial customers beginning July 1, 2004, and to its residential customers beginning July 1, 2006, through a competitive wholesale bidding process as discussed in the Electric Competition—Standard Offer Service—Provider of Last Resort (POLR) section.

        BGE may receive performance assurance collateral from suppliers to mitigate suppliers' credit risks in certain circumstances. Performance assurance collateral is designed to protect BGE's potential exposure over the term of the supply contracts and will fluctuate to reflect changes in market prices. In addition to the collateral provisions, there are supplier "step-up" provisions, where other suppliers can step in if the early termination of a Full-Requirements Service Agreement with a supplier should occur, as well as specific mechanisms for BGE to otherwise replace defaulted supplier contracts. All costs incurred by BGE to replace the supply contract are to be recovered from the defaulting supplier or from customers through rates. Finally, BGE's exposure to uncollectible expense or credit risk from customers for the commodity portion of the bill is covered by the administrative fee included in POLR rates.

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 13. At December 31, 2003 and 2002, our exposure to commodity price risk for our regulated gas business was not material.

Credit Risk

We are exposed to credit risk, primarily through our merchant energy business. Credit risk is the loss that may result from a counterparty's nonperformance. We evaluate our credit risk for our wholesale marketing and risk management operation and our retail competitive supply activities separately as discussed below.

Wholesale Credit Risk

We measure wholesale credit risk as the replacement cost for open energy commodity and derivative transactions (both mark-to-market and accrual) adjusted for amounts owed to or due 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. We monitor and manage the credit risk of our wholesale marketing and risk management operation through credit policies and procedures which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral, or prepayment arrangements, and the use of master netting agreements.

        During 2003, we continued to observe significant declines in the creditworthiness of several major participants in the wholesale energy markets. We continue to actively manage the credit portfolio of our wholesale marketing and risk management operation to attempt to reduce the impact of the general decline in the overall credit quality of the energy industry and the impact of a potential counterparty default. As of December 31, 2003 and 2002, the credit portfolio of our wholesale marketing and risk management operation had the following public credit ratings:

At December 31,

  2003
  2002
 

 
Rating          
  Investment Grade1   75 % 85 %
  Non-Investment Grade   4   3  
  Not Rated   21   12  

1  Includes counterparties with an investment grade rating by at least one of the major credit rating agencies. If split rating exists, the lower rating is used.

        The reduction in the percentage of counterparties with investment grade ratings to 75% in 2003 is primarily due to increased business activity with counterparties that do not have public credit ratings. These "Not Rated" counterparties include governmental entities, municipalities, cooperatives, power pools, other load-serving entities, and marketers for which we determine creditworthiness based on our internal credit ratings.

        In addition to the credit ratings provided by the major credit rating agencies, we utilize internal credit ratings to evaluate the creditworthiness of our wholesale customers, including those companies that do not have public credit ratings. The following table provides the breakdown of the credit quality of our wholesale credit portfolio based on our internal credit ratings.

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At December 31,

  2003
  2002
 

 
Investment Grade Equivalent   91 % 95 %
Non-Investment Grade   9   5  

        A portion of our wholesale credit risk is related to transactions that are recorded in our Consolidated Balance Sheets. These transactions primarily consist of open positions from our wholesale marketing and risk management operation that are accounted for using mark-to-market accounting, as well as amounts owed by wholesale counterparties for transactions that settled but have not yet been paid. The following table highlights the credit quality and exposures related to these activities:

Rating

  Total
Exposure
Before
Credit
Collateral

  Credit
Collateral

  Net
Exposure

  Number of Counterparties Greater than 10% of Net Exposure
  Net Exposure of Counterparties Greater than 10% of Net Exposure
(Dollars in millions)

Investment grade   $ 577   $ 38   $ 539   1   $ 90
Split rating     8         8      
Non-investment grade     138     102     36      
Internally rated—investment grade     224     110     114      
Internally rated—non-investment grade     28     4     24      

Total   $ 975   $ 254   $ 721   1   $ 90

        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 our wholesale marketing and risk management operation had contracted for), we could incur a loss that could have a material impact on our financial results.

        Additionally, if a counterparty were to default and we were to liquidate all contracts with that entity, our credit loss would include the loss in value of mark-to-market contracts, the amount owed for settled transactions, and additional payments, if any, we would have to make to settle unrealized losses on accrual contracts.

Retail Credit Risk

We are exposed to retail credit risk through our competitive electricity and natural gas supply activities which serve commercial and industrial companies. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that may be incurred due to the nonpayment of a customer's accounts receivable balance, as well as the loss from the resale of energy previously committed to serve the customer.

        Retail credit risk is managed through established credit policies, monitoring customer exposures, a diversified portfolio with no significant concentration (customer or industry), and the use of credit mitigation measures such as letters of credit or prepayment arrangements.

        During 2003, we did not experience a material change in the credit quality of our retail credit portfolio compared to 2002. Retail credit quality is dependent on the economy and the ability of our customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, our retail credit risk may be adversely impacted.

Equity Price Risk

We are exposed to price fluctuations in equity markets primarily through our pension plan assets, our nuclear decommissioning trust funds, trust assets securing certain executive benefits, and our financial investments operation. 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 $75 million reduction in the fair value of our financial investments that are classified as trading or available-for-sale securities. In 2003, the value of our defined benefit pension plan assets increased by approximately $185 million due to advances 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.

58



Item 8. Financial Statements and Supplementary Data

REPORT OF MANAGEMENT

The management of Constellation Energy and BGE (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 Financial Officer, conducts periodic reviews to maintain the effectiveness of internal control procedures. PricewaterhouseCoopers LLP, independent auditors, 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 four independent 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.

GRAPHIC

Mayo A. Shattuck III
Chairman of the Board, President and Chief Executive Officer
  GRAPHIC

E. Follin Smith
Executive Vice-President and Chief Financial Officer

REPORT OF INDEPENDENT AUDITORS

To the Board of Directors and 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 15(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, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 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 15(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 statements of capitalization of Constellation Energy Group, Inc. and Subsidiaries and of Baltimore Gas and Electric Company and Subsidiaries as of December 31, 2001, 2000 and 1999, and the related consolidated statements of income, cash flows, and common shareholders' equity and comprehensive income for the years ended December 31, 2000 and 1999 (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, 2003, 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, 2003, 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, in 2003, the Companies changed their method of accounting for recording asset retirement obligations pursuant to Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, and the accounting for certain energy contracts pursuant to Emerging Issues Task Force Issue 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. As discussed in Note 1 to the consolidated financial statements, in 2001, 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).

GRAPHIC

PricewaterhouseCoopers LLP
Atlanta, Georgia
January 28, 2004

59


CONSOLIDATED STATEMENTS OF INCOME

Constellation Energy Group, Inc. and Subsidiaries

Year Ended December 31,

  2003
  2002
  2001
 

 
 
  (In millions, except per share amounts)
 
Revenues                    
  Nonregulated revenues   $ 7,068.8   $ 2,190.6   $ 1,164.9  
  Regulated electric revenues     1,921.5     1,965.6     2,039.6  
  Regulated gas revenues     712.7     570.5     674.3  

 
  Total revenues     9,703.0     4,726.7     3,878.8  

Expenses

 

 

 

 

 

 

 

 

 

 
  Operating expenses     7,863.3     3,073.6     2,392.2  
  Workforce reduction costs     2.1     62.8     105.7  
  Impairment losses and other costs     0.6     25.2     158.8  
  Contract termination related costs             224.8  
  Depreciation and amortization     479.0     481.0     419.1  
  Accretion of asset retirement obligations     42.7          
  Taxes other than income taxes     275.2     259.2     226.6  

 
  Total expenses     8,662.9     3,901.8     3,527.2  

Net Gain on Sales of Investments and Other Assets

 

 

26.2

 

 

261.3

 

 

6.2

 

 
Income from Operations     1,066.3     1,086.2     357.8  

Other Income

 

 

19.1

 

 

30.5

 

 

1.3

 

Fixed Charges

 

 

 

 

 

 

 

 

 

 
  Interest expense     340.8     312.3     283.2  
  Interest capitalized and allowance for borrowed funds used during construction     (13.8 )   (44.0 )   (57.6 )
  BGE preference stock dividends     13.2     13.2     13.2  

 
  Total fixed charges     340.2     281.5     238.8  

 
Income Before Income Taxes     745.2     835.2     120.3  
Income Taxes     269.5     309.6     37.9  

 
Income Before Cumulative Effects of Changes in Accounting Principles     475.7     525.6     82.4  
Cumulative Effects of Changes in Accounting Principles, Net of Income Taxes of $119.5 and $5.6 (see Note 1)     (198.4 )       8.5  

 
Net Income   $ 277.3   $ 525.6   $ 90.9  

 

Earnings Applicable to Common Stock

 

$

277.3

 

$

525.6

 

$

90.9

 

 
Average Shares of Common Stock Outstanding—Basic     166.3     164.2     160.7  
Average Shares of Common Stock Outstanding—Assuming Dilution     166.7     164.2     160.7  

Earnings Per Common Share Before Cumulative Effects of Changes in Accounting Principles—Basic

 

$

2.86

 

$

3.20

 

$

0.52

 
Cumulative Effects of Changes in Accounting Principles     (1.19 )       0.05  

 
Earnings Per Common Share—Basic   $ 1.67   $ 3.20   $ 0.57  

 

Earnings Per Common Share Before Cumulative Effects of Changes in Accounting Principles—Assuming Dilution

 

$

2.85

 

$

3.20

 

$

0.52

 
Cumulative Effects of Changes in Accounting Principles     (1.19 )       0.05  

 
Earnings Per Common Share—Assuming Dilution   $ 1.66   $ 3.20   $ 0.57  

 
Dividends Declared Per Common Share   $ 1.04   $ 0.96   $ 0.48  

 

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

Constellation Energy Group, Inc. and Subsidiaries

At December 31,

  2003

  2002

 

 
 
  (In millions)

 
Assets              
  Current Assets              
    Cash and cash equivalents   $ 721.3   $ 615.0  
    Accounts receivable (net of allowance for uncollectibles
of
$51.7 and $41.9, respectively)
    1,563.0     1,244.1  
    Mark-to-market energy assets     555.2     759.4  
    Risk management assets     256.0     72.3  
    Materials and supplies     211.7     208.6  
    Fuel stocks     178.2     126.5  
    Acquired contracts, net of amortization     67.0     70.8  
    Prepaid taxes other than income taxes     62.4     57.1  
    Other     92.0     163.4  

 
    Total current assets     3,706.8     3,317.2  

 
 
Investments and Other Assets

 

 

 

 

 

 

 
    Nuclear decommissioning trust funds     736.1     645.4  
    Investments in qualifying facilities and power projects     332.6     439.2  
    Mark-to-market energy assets     286.9     926.8  
    Risk management assets     269.9     88.8  
    Goodwill     144.0     115.9  
    Acquired contracts, net of amortization     105.8     64.0  
    Other     238.0     253.1  

 
    Total investments and other assets     2,113.3     2,533.2  

 
 
Property, Plant and Equipment

 

 

 

 

 

 

 
    Regulated property, plant and equipment              
      Plant in service     5,131.7     4,952.4  
      Construction work in progress     130.5     118.3  
      Plant held for future use     4.5     4.5  

 
      Total regulated property, plant and equipment     5,266.7     5,075.2  
    Nonregulated generation property, plant and equipment     7,769.1     6,811.9  
    Other nonregulated property, plant and equipment     340.9     242.0  
    Nuclear fuel (net of amortization)     202.9     224.8  
    Accumulated depreciation     (3,978.1 )   (3,694.3 )

 
    Net property, plant and equipment     9,601.5     8,659.6  

 
 
Deferred Charges

 

 

 

 

 

 

 
    Regulatory assets (net)     229.5     297.3  
    Other     149.6     136.0  

 
    Total deferred charges     379.1     433.3  

 

 

 

 

 

 

 

 

 

Total Assets

 

$

15,800.7

 

$

14,943.3

 

 

See Notes to Consolidated Financial Statements.

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

61


CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

At December 31,

  2003

  2002


 
  (In millions)

Liabilities and Equity            
  Current Liabilities            
    Short-term borrowings   $ 9.6   $ 10.5
    Current portion of long-term debt     343.2     426.2
    Accounts payable     1,167.7     943.4
    Customer deposits and collateral     181.7     102.8
    Mark-to-market energy liabilities     541.5     709.6
    Risk management liabilities     140.4     20.1
    Accrued taxes     127.2     15.0
    Accrued interest     83.1     95.5
    Dividends declared     46.8     42.8
    Other     266.5     298.6

    Total current liabilities     2,907.7     2,664.5

 
Deferred Credits and Other Liabilities

 

 

 

 

 

 
    Deferred income taxes     1,384.4     1,330.7
    Mark-to-market energy liabilities     283.0     460.0
    Risk management liabilities     282.3     149.5
    Asset retirement obligations     595.9     594.1
    Postretirement and postemployment benefits     361.8     352.8
    Net pension liability     225.7     334.6
    Deferred investment tax credits     78.4     85.7
    Other     198.4     199.9

    Total deferred credits and other liabilities     3,409.9     3,507.3

 
Capitalization (See Consolidated Statements of Capitalization)

 

 

 

 

 

 
    Long-term debt     5,039.2     4,613.9
    Minority interests     113.4     105.3
    BGE preference stock not subject to mandatory redemption     190.0     190.0
    Common shareholders' equity     4,140.5     3,862.3

    Total capitalization     9,483.1     8,771.5

 
Commitments, Guarantees, and Contingencies (see Note 12)

 

 

 

 

 

 

Total Liabilities and Equity

 

$

15,800.7

 

$

14,943.3


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

62


CONSOLIDATED STATEMENTS OF CASH FLOWS

Constellation Energy Group, Inc. and Subsidiaries

Year Ended December 31,

  2003
  2002
  2001
 

 
 
  (In millions)

 
Cash Flows From Operating Activities                    
  Net income   $ 277.3   $ 525.6   $ 90.9  
  Adjustments to reconcile to net cash provided by operating activities                    
    Cumulative effects of changes in accounting principles     198.4         (8.5 )
    Depreciation and amortization     600.0     548.0     468.9  
    Accretion of asset retirement obligations     42.7          
    Deferred income taxes     109.2     148.3     (26.5 )
    Investment tax credit adjustments     (7.3 )   (7.9 )   (8.1 )
    Deferred fuel costs     (10.1 )   23.9     37.6  
    Pension and postemployment benefits     (69.4 )   (116.2 )   55.3  
    Net gain on sales of investments and other assets     (26.2 )   (261.3 )   (6.2 )
    Workforce reduction costs     2.1     62.8     105.7  
    Impairment losses and other costs     0.6     25.2     158.8  
    Contract termination related costs             26.2  
    Equity in earnings of affiliates less than dividends received     38.4     67.0     2.0  
    Changes in                    
      Accounts receivable     (291.0 )   (236.8 )   53.7  
      Mark-to-market energy assets and liabilities     29.9     (133.7 )   109.5  
      Risk management assets and liabilities     (83.5 )   58.6     (93.2 )
      Materials, supplies and fuel stocks     (51.5 )   (11.7 )   (90.9 )
      Other current assets     19.3     130.3     (20.5 )
      Accounts payable     204.1     188.4     (226.7 )
      Other current liabilities     107.4     53.9     (20.3 )
      Other     (10.3 )   (44.4 )   (34.4 )

 
  Net cash provided by operating activities     1,080.1     1,020.0     573.3  

 

Cash Flows From Investing Activities

 

 

 

 

 

 

 

 

 

 
  Investments in property, plant and equipment     (658.0 )   (831.9 )   (1,302.5 )
  Acquisitions, net of cash acquired     (546.6 )   (221.4 )   (382.7 )
  Contributions to nuclear decommissioning trust funds     (13.2 )   (17.6 )   (22.0 )
  Sale of investments and other assets     148.8     838.0     287.1  
  Other investments     (113.6 )   (86.9 )   (52.6 )

 
  Net cash used in investing activities     (1,182.6 )   (319.8 )   (1,472.7 )

 

Cash Flows From Financing Activities

 

 

 

 

 

 

 

 

 

 
  Net (maturity) issuance of short-term borrowings     (0.9 )   (964.5 )   731.4  
  Proceeds from issuance of                    
    Long-term debt     983.3     2,529.3     1,175.2  
    Common stock     95.4     28.5     504.4  
  Repayment of long-term debt     (707.5 )   (1,627.7 )   (1,510.2 )
  Common stock dividends paid     (169.2 )   (137.8 )   (120.7 )
  Other     7.7     14.6     9.0  

 
  Net cash provided by (used in) financing activities     208.8     (157.6 )   789.1  

 
Net Increase (Decrease) in Cash and Cash Equivalents     106.3     542.6     (110.3 )
Cash and Cash Equivalents at Beginning of Year     615.0     72.4     182.7  

 
Cash and Cash Equivalents at End of Year   $ 721.3   $ 615.0   $ 72.4  

 

Other Cash Flow Information:

 

 

 

 

 

 

 

 

 

 
  Cash paid during the year for:                    
    Interest (net of amounts capitalized)   $ 339.4   $ 230.5   $ 238.3  
    Income taxes   $ 34.0   $ 157.8   $ 101.5  

Non-Cash Transaction:

 

 

 

 

 

 

 

 

 

 
  In connection with our purchase of Nine Mile Point in 2001, 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.  

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

63


CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME

Constellation Energy Group, Inc. and Subsidiaries

 
   
   
   
  Accumulated Other Comprehensive Income (Loss)
   
 
Year Ended December 31, 2003, 2002, and 2001

  Common Stock

  Retained
Earnings

  Total Amount
 
  Shares
  Amount
 

 
 
  (Dollar amounts in millions, number of shares in thousands)

 

Balance at December 31, 2000

 

150,532

 

$

1,538.7

 

$

1,592.3

 

$

43.0

 

$

3,174.0

 

Comprehensive Income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Net income               90.9           90.9  
  Other comprehensive income (OCI)                              
    Cumulative effect of change in accounting principle, net of taxes of $22.6                     (35.5 )   (35.5 )
    Reclassification of net gain on sales of securities from OCI to net income, net of taxes of $15.7                     (24.0 )   (24.0 )
    Net unrealized gain on securities, net of taxes of $87.5                     148.5     148.5  
    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 )

 
Total Comprehensive Income               90.9     146.9     237.8  
Common stock dividend declared ($0.48 per share)               (77.1 )         (77.1 )
Common stock issued   13,176     504.4                 504.4  
Other         (0.9 )   5.4           4.5  

 
Balance at December 31, 2001   163,708     2,042.2     1,611.5     189.9     3,843.6  

Comprehensive Income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Net income               525.6           525.6  
  Other comprehensive income                              
    Reclassification of net gain on sales of securities from OCI to net income, net of taxes of $87.7                     (152.8 )   (152.8 )
    Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $10.9                     (17.8 )   (17.8 )
    Net unrealized loss on securities, net of taxes of $28.6                     (43.2 )   (43.2 )
    Net unrealized loss on hedging instruments, net of taxes of $31.7                     (52.2 )   (52.2 )
    Minimum pension liability, net of taxes of $77.2                     (118.1 )   (118.1 )

 
Total Comprehensive Income               525.6     (384.1 )   141.5  
Common stock dividend declared ($0.96 per share)               (157.6 )         (157.6 )
Common stock issued   1,135     28.5                 28.5  
Other         8.2     (1.9 )         6.3  

 
Balance at December 31, 2002   164,843     2,078.9     1,977.6     (194.2 )   3,862.3  

Comprehensive Income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Net income               277.3           277.3  
  Other comprehensive income                              
    Reclassification of net gain on sales of securities from OCI to net income, net of taxes of $0.2                     (0.4 )   (0.4 )
    Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $10.7                     (16.4 )   (16.4 )
    Net unrealized gain on securities, net of taxes of $24.4                     37.3     37.3  
    Net unrealized gain on hedging instruments, net of taxes of $15.8                     39.9     39.9  
    Minimum pension liability, net of taxes of $8.2                     12.6     12.6  

 
Total Comprehensive Income               277.3     73.0     350.3  
Common stock dividend declared ($1.04 per share)               (172.8 )         (172.8 )
Common stock issued   2,976     100.9                 100.9  
Other               (0.2 )         (0.2 )

 
Balance at December 31, 2003   167,819   $ 2,179.8   $ 2,081.9   $ (121.2 ) $ 4,140.5  

 

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

64


CONSOLIDATED STATEMENTS OF CAPITALIZATION

Constellation Energy Group, Inc. and Subsidiaries

At December 31,

  2003
  2002
 

 
 
  (In millions)
 
Long-Term Debt              
  Long-term debt of Constellation Energy              
    77/8% Notes, due April 1, 2005   $ 300.0   $ 300.0  
    6.35% Fixed Rate Notes, due April 1, 2007     600.0     600.0  
    6.125% Fixed Rate Notes, due September 1, 2009     500.0     500.0  
    7.00% Fixed Rate Notes, due April 1, 2012     700.0     700.0  
    4.55% Fixed Rate Notes, due June 15, 2015     550.0      
    7.60% Fixed Rate Notes, due April 1, 2032     700.0     700.0  

 
    Total long-term debt of Constellation Energy     3,350.0     2,800.0  

 
  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  
    District Cooling facilities loan, due December 1, 2031     25.0     25.0  
    Loans under revolving credit agreements     46.3     51.7  
    Geothermal facilities loan, due September 30, 2011     45.3      
    4.25% Mortgage note, due March 15, 2009     2.8     3.3  

 
    Total long-term debt of nonregulated businesses     389.2     349.8  

 
  First Refunding Mortgage Bonds of BGE              
    61/2% Series, due February 15, 2003         124.8  
    61/8% Series, due July 1, 2003         124.9  
    51/2% Series, due April 15, 2004     125.0     125.0  
    Remarketed floating rate series, due September 1, 2006     104.1     111.5  
    71/2% Series, due January 15, 2007     122.5     123.5  
    65/8% Series, due March 15, 2008     124.5     124.9  
    71/2% Series, due March 1, 2023         98.1  
    71/2% Series, due April 15, 2023         72.2  

 
    Total First Refunding Mortgage Bonds of BGE     476.1     904.9  

 
  Other long-term debt of BGE              
    5.25% Notes, due December 15, 2006     300.0     300.0  
    5.20% Notes, due June 15, 2033     200.0      
    Medium-term notes, Series B     12.1     12.1  
    Medium-term notes, Series C         25.5  
    Medium-term notes, Series D     68.0     68.0  
    Medium-term notes, Series E     199.5     199.5  
    Medium-term notes, Series G     140.0     140.0  

 
    Total other long-term debt of BGE     919.6     745.1  

 
  6.20% deferrable interest subordinated debentures due October 15, 2043 to BGE wholly owned BGE Capital Trust II relating to trust preferred securities     257.7      
  BGE obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% deferrable interest subordinated debentures due June 30, 2038         250.0  
  Unamortized discount and premium     (10.2 )   (9.7 )
  Current portion of long-term debt     (343.2 )   (426.2 )

 
Total long-term debt   $ 5,039.2   $ 4,613.9  

 

See Notes to Consolidated Financial Statements.

continued on next page

65


CONSOLIDATED STATEMENTS OF CAPITALIZATION

Constellation Energy Group, Inc. and Subsidiaries

At December 31,

  2003
  2002
 

 
 
  (In millions)
 

Minority Interests

 

$

113.4

 

$

105.3

 

BGE Preference Stock

 

 

 

 

 

 

 
  Cumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized              
    7.125%, 1993 Series, 400,000 shares outstanding, callable at $103.21 per share until June 30, 2004, and at lesser amounts thereafter     40.0     40.0  
    6.97%, 1993 Series, 500,000 shares outstanding, callable at $103.14 per share until September 30, 2004, and at lesser amounts thereafter     50.0     50.0  
    6.70%, 1993 Series, 400,000 shares outstanding, callable at $103.34 per share until December 31, 2004, and at lesser amounts thereafter     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; 167,819,338 and 164,842,708 shares issued and outstanding at December 31, 2003 and 2002, respectively. (At December 31, 2003, 18,000,000 shares were reserved for the long-term incentive plans, 10,751,569 shares were reserved for the Shareholder Investment Plan, 520,000 shares were reserved for the continuous offering programs, and 945,018 shares were reserved for the employee savings plan.)     2,179.8     2,078.9  
  Retained earnings     2,081.9     1,977.6  
  Accumulated other comprehensive loss     (121.2 )   (194.2 )

 
  Total common shareholders' equity     4,140.5     3,862.3  

 
Total Capitalization   $ 9,483.1   $ 8,771.5  

 

See Notes to Consolidated Financial Statements.

66


CONSOLIDATED STATEMENTS OF INCOME

Baltimore Gas and Electric Company and Subsidiaries

Year Ended December 31,

  2003
  2002
  2001
 

 
 
  (In millions)
 
Revenues                    
  Electric revenues   $ 1,921.6   $ 1,966.0   $ 2,040.0  
  Gas revenues     726.0     581.3     680.7  

 
  Total revenues     2,647.6     2,547.3     2,720.7  
Expenses                    
  Operating Expenses                    
    Electric fuel and purchased energy     1,023.5     1,080.7     1,192.8  
    Gas purchased for resale     445.8     316.7     401.3  
    Operations and maintenance     395.4     355.3     363.0  
    Workforce reduction costs     0.7     35.3     57.0  
  Depreciation and amortization     228.3     221.6     221.0  
  Taxes other than income taxes     168.9     171.4     173.8  

 
  Total expenses     2,262.6     2,181.0     2,408.9  

 
Income from Operations     385.0     366.3     311.8  
Other (Expense) Income     (5.4 )   10.7     0.4  
Fixed Charges                    
  Interest expense     112.8     142.1     156.2  
  Allowance for borrowed funds used during construction     (1.6 )   (1.5 )   (1.6 )

 
  Total fixed charges     111.2     140.6     154.6  

 
Income Before Income Taxes     268.4     236.4     157.6  
Income Taxes                    
  Current     48.5     67.4     62.4  
  Deferred     58.5     28.0     0.2  
  Investment tax credit adjustments     (1.8 )   (2.1 )   (2.3 )

 
  Total income taxes     105.2     93.3     60.3  

 
Net Income     163.2     143.1     97.3  
Preference Stock Dividends     13.2     13.2     13.2  

 
Earnings Applicable to Common Stock   $ 150.0   $ 129.9   $ 84.1  

 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Baltimore Gas and Electric Company and Subsidiaries

Year Ended December 31,

  2003
  2002
  2001

 
  (In millions)
Net Income   $ 150.0   $ 129.9   $ 84.1
  Other comprehensive income                  
    Unrealized gain on hedging instruments, net of taxes of $0.4     0.8        

Comprehensive Income   $ 150.8   $ 129.9   $ 84.1

See Notes to Consolidated Financial Statements.

67


CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

At December 31,

  2003
  2002
 

 
 
  (In millions)
 
Assets              
  Current Assets              
    Cash and cash equivalents   $ 11.0   $ 10.2  
    Accounts receivable (net of allowance for uncollectibles
of
$10.7 and $11.5, respectively)
    354.8     357.5  
    Investment in cash pool, affiliated company     230.2     338.1  
    Accounts receivable, affiliated companies     4.5     131.2  
    Fuel stocks     62.8     40.6  
    Materials and supplies     29.9     31.8  
    Prepaid taxes other than income taxes     42.8     42.0  
    Other     9.9     10.3  

 
    Total current assets     745.9     961.7  

 
 
Investments and Other Assets

 

 

 

 

 

 

 
    Receivable, affiliated company     131.6     63.3  
    Other     90.4     85.9  

 
    Total other assets     222.0     149.2  

 
 
Utility Plant

 

 

 

 

 

 

 
    Plant in service              
      Electric     3,599.3     3,422.3  
      Gas     1,064.7     1,041.0  
      Common     467.7     489.1  

 
      Total plant in service     5,131.7     4,952.4  
    Accumulated depreciation     (1,807.7 )   (1,743.0 )

 
    Net plant in service     3,324.0     3,209.4  
    Construction work in progress     130.5     118.3  
    Plant held for future use     4.5     4.5  

 
    Net utility plant     3,459.0     3,332.2  

 
 
Deferred Charges

 

 

 

 

 

 

 
    Regulatory assets (net)     229.5     297.3  
    Other     50.2     39.5  

 
    Total deferred charges     279.7     336.8  

 
   
Total Assets