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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

FORM 10-K

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

For the fiscal year endedDECEMBER 31, 2002

Commission
file number

Exact name of registrant as specified in its charter

IRS Employer Identification No.1-12869

CONSTELLATION ENERGY GROUP, INC.

52-19646111-1910

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)

410-234-5000

(Registrants' telephone number, including area code)

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

|Title of each class                                                                                                                                                                                                                  |   |  | Name of Each Exchange on Which Registered                                        
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ | - |  | ---------------------------------------------------------------------------------
|Constellation Energy Group, Inc. Common StockWithout Par Value                                                                                                                                                                      | ) |  | New York Stock Exchange, Inc.
Chicago Stock Exchange, Inc.
Pacific Exchange, Inc.
|7.16% Trust Originated Preferred Securities ($25 liquidation amount per preferred security) issued by BGE Capital Trust I, fully and unconditionally guaranteed, based on several obligations, by Baltimore Gas and Electric Company | ) |  | New York Stock Exchange, Inc.                                                    

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

Not Applicable

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

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

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

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE

|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 April 25, 2003.

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.

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TABLE OF CONTENTS



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|PART II 
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|PART III
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|PART IV 
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Forward Looking Statements

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



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

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

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PART I

Item 1. Business

Overview

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

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

1

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

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

Our
merchant energy business includes:



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

Our
other nonregulated businesses:



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

For
a discussion of recent events that have impacted Constellation Energy, please refer toItem 7. Management's Discussion and AnalysisSignificant
Eventssection. For a discussion of Constellation Energy's strategy, please refer toItem
7. Management's Discussion and AnalysisStrategysection. For a discussion of the seasonality of our business, please refer toItem 7.
Management's Discussion and AnalysisBusiness Environmentsection.

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, inNote 3 to Consolidated Financial Statements. Effective July 1, 2000, the financial results of the electric
generation portion of our business are included in the merchant energy business segment. Prior to that date, the financial results are included in the regulated electric segment.

|     |  | Unaffiliated Revenues |  
|---- |  | --------------------- | -
|
|2002 |  | 35                    | %
|2001 |  | 16                    |  
|2000 |  | 11                    |  

|     |  | Net income(1) |  
|---- |  | ------------- | -
|
|2002 |  | 67            | %
|2001 |  | 75            |  
|2000 |  | 68            |  

|     |  | Total Assets |  
|---- |  | ------------ | -
|
|2002 |  | 63           | %
|2001 |  | 57           |  
|2000 |  | 56           |  

2

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Merchant Energy Business

Introduction

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

Our
merchant energy business:



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



We
present details about our generating properties inItem 2. Properties.

PJM Platform

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

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

These
facilities include the Calvert Cliffs Nuclear Power Plant (two units), which is our largest generating station. In March 2000, Calvert Cliffs became the first nuclear power plant
in the United States to achieve license renewal. The Nuclear Regulatory Commission (NRC) approved a twenty-year license renewal for both units of Calvert Cliffs, extending the license for Unit 1 to
2034 and for Unit 2 to 2036.

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

Plants with Power Purchase Agreements

We own 2,530 MW of nuclear and natural gas generation capacity, and have under construction an 830 MW natural gas-fired facility that will commence operation in 2003, with
power purchase agreements for their output. These facilities include Nine Mile Point, which is our second largest generating station. We purchased 100% of Unit 1 (609 MW) and 82% of Unit 2 (941 MW) in
November 2001. The remaining interest in Nine Mile Point Unit 2 is owned by a subsidiary of the Long Island Power Authority. Unit 1 entered service in 1969 and Unit 2 in 1988. Nine Mile Point is
located within the New York Independent System Operator (NYISO) region.

We
sell 90 percent of our share of the Nine Mile Point plant's output back to the sellers at an average price of nearly $35 per megawatt-hour (MWH) under agreements that terminate
between 2009 and 2010. The agreements for the output of both units are unit contingent (if the output is not available because the plant is not operating, there is no requirement to provide output
from other sources). The remaining 10% of Nine Mile Point's output is managed by our origination and risk management operation and sold into the wholesale market.

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

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

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

Our
other facilities with power purchase agreements consist of:



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

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

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

Competitive Supply

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

Origination of Structured Transactions

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

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

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

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



Risk Management Activities

Our origination and risk management operation actively uses energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers
through structured transactions, to obtain market intelligence, and to take advantage of arbitrage opportunities that exist across different markets. These activities involve the use of a variety of
instruments, including:



4

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

Other

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

In
addition, we hold up to a 50% ownership interest in 28 operating energy projects that consist of electric generation (primarily relying on alternative fuel sources), fuel processing,
or fuel handling facilities and are either qualifying facilities under the Public Utility Regulatory Policies Act of 1978 or otherwise exempt from, or not subject to, the Public Utility Holding
Company Act of 1935. Each electric generating plant sells its output to a local utility under long-term contracts.

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

We
also provide the following services:



Fuel Sources

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

|Fuel                         |  | Capacity Owned |   | Generation |  
|---------------------------- |  | -------------- | - | ---------- | -
|Nuclear                      |  | 28.6           | % | 53.4       | %
|Coal                         |  | 24.2           |   | 35.7       |  
|Natural Gas                  |  | 25.6           |   | 3.3        |  
|Oil                          |  | 6.7            |   | 1.3        |  
|Renewable and Alternative(1) |  | 4.3            |   | 4.3        |  
|Dual(2)                      |  | 10.6           |   | 2.0        |  

We discuss our risks associated with fuel in more detail inItem 7. Management's Discussion and AnalysisMarket Risksection.

Nuclear

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

|     |  | Generation
MWH |  | Capacity
Factor |  
|---- |  | -------------- |  | --------------- | -
|2002 |  | 12,087,408     |  | 82              | %
|2001 |  | 13,648,932     |  | 92              |  
|2000 |  | 13,826,046     |  | 93              |  
|1999 |  | 13,309,306     |  | 91              |  
|1998 |  | 13,326,633     |  | 91              |  

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

|     |  | Generation
MWH* |  | Capacity
Factor |  
|---- |  | --------------- |  | --------------- | -
|2002 |  | 11,727,567      |  | 87              | %
|2001 |  | 11,613,519      |  | 86              |  
|2000 |  | 11,243,095      |  | 83              |  
|1999 |  | 10,766,425      |  | 79              |  
|1998 |  | 10,837,848      |  | 80              |  

*represents our proportionate ownership interest

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The supply of fuel for nuclear generating stations includes the:



|Uranium
Concentrates:      |  | We have under contract sufficient quantities of uranium to meet 100% of both Calvert Cliffs' and Nine Mile Point's requirements through 2004, 50% for both plants in 2005, 60% for both plants in 2006 and 25% for both plants in 2007.                                                        
|-------------------------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Conversion:                |  | We have contractual commitments providing for the conversion of uranium concentrate into uranium hexafluoride that will meet 100% of Calvert Cliffs' and Nine Mile Point's requirements through 2004, 50% for
both plants in 2005, 67% for both plants in 2006 and 50% for both plants in 2007.
|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 2005 for Nine Mile Point Unit 2 and through 2009 for Nine Mile Point Unit 1.                                                                                         

The nuclear fuel markets are competitive and we do not anticipate any problem in meeting our future requirements.

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

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

On
February 14, 2002, the Secretary of Energy submitted to the President a recommendation for approval of the Yucca Mountain site for the development of a nuclear waste repository for
the disposal of spent nuclear fuel and high level nuclear waste from the nation's defense activities. In July 2002, the President signed a resolution approving the Yucca Mountain site after receiving
the approval of the U.S. Senate and House of Representatives. This action allows the Department of Energy to apply to the NRC to license the project. The Department of Energy currently expects that
this facility will open in 2010. However, the opening of Yucca Mountain could be delayed due to multiple lawsuits initiated by the State of Nevada and other interested parties, the NRC licensing
hearings, and other issues related to the site.

Storage of Spent Nuclear FuelOn-Site FacilitiesCalvert Cliffs has a license from the NRC to operate an on-site independent spent fuel storage installation that expires in 2012. We have storage capacity at Calvert Cliffs that will accommodate spent
fuel from operations through 2008. In addition, we can expand our temporary storage capacity at Calvert Cliffs to meet future requirements until approximately 2025. Currently, Nine Mile Point does not
have independent spent fuel storage capacity. Rather, Nine Mile Point's Unit 1 has sufficient storage capacity within the plant until the end of its current operating license in 2009. If license
renewal is obtained, independent spent fuel storage capability will need to be developed. Nine Mile Point's Unit 2 has sufficient storage capacity within the plant until 2012. After that time
independent spent fuel storage capability may need to be developed.

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

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

The
sellers of Nine Mile Point transferred a $441.7 million decommissioning trust fund at the time of sale. In return, Nine Mile Point assumed all liability for the costs to decommission
Unit 1 and 82% of the cost to decommission Unit 2. We believe that this amount is adequate to cover our responsibility for decommissioning Nine Mile Point to a greenfield status (restoration of the
site so that it substantially matches the natural state of the surrounding properties and the site's intended use). At December 31, 2002, the Nine Mile Point trust fund was $405.7 million.

CoalWe 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 0.8% 
|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 coal we use is produced from mines located in central and northern Appalachia.

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

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

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

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

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

Competition

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

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

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

During
the transition of the energy industry to competitive markets, it is difficult for us to assess our position versus the position of existing power providers and new entrants
because each company may employ widely differing strategies in their fuel supply and power sales contracts with regard to pricing, terms and conditions. Further difficulties in making competitive
assessments of our company arise from states considering different types of regulatory initiatives concerning competition in the power industry. Increased competition that resulted from some of these
initiatives in several states contributed in some instances to a reduction in electricity prices and put pressure on electric utilities to lower their costs, including the cost of purchased
electricity. In addition, some states that were considering deregulation have slowed their plans or postponed consideration of deregulation.

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

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

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Merchant Energy Operating Statistics

|                            |                                       | 2002          |      | 2001    |         | 2000 |         | 1999    |      | 1998 
|--------------------------- | ------------------------------------- | ------------- | ---- | ------- | ------- | ---- | ------- | ------- | ---- | -----
|
|Revenues(In millions)       |                                       |               |      |         |         |      |         |         |      |      
|                            | PJM Platform                          |               | $    | 1,391.4 |         | $    | 1,379.2 |         | $    | 731.7
|                            | Plants with Power Purchase Agreements |               |      | 456.4   |         |      | 70.8    |         |      |     
|                            | Competitive SupplyAccrual Revenues   |               |      | 587.6   |         |      |        |         |      |     
|                            | Mark-to-Market
Revenues              |               |      | 238.1   |         |      | 175.8   |         |      | 151.5
|                            | Other                                 |               |      | 92.2    |         |      | 139.7   |         |      | 142.5
|                           
|                            |                                       | Total Revenue |      | $       | 2,765.7 |      | $       | 1,765.5 |      | $    
|                           
|Generation(In millions)MWH |                                       |               | 44.7 |         |         | 37.4 |         |         | 18.8 |      
|                           

Operating statistics do not reflect the elimination of intercompany transactions.

8

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Baltimore Gas and Electric Company

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

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

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

Electric Business

Electric Regulatory Matters and Competition

Deregulation

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



Standard Offer Service

Our origination and risk management operation provides BGE with 100% of the energy and capacity required to meet its standard offer service obligations through June 30, 2003.
Beginning July 1, 2003, this operation will provide 90% and Allegheny Energy Supply Company, LLC will provide the remaining 10% of the energy and capacity required for BGE to meet its standard offer
service obligations until June 30, 2006.

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

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

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

9

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

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

Competition

The electric transmission and distribution services are facing competition from alternative energy sources that include on-site generation and cogeneration projects. In future
years, emerging technologies, including fuel cells and solar panels, may also become a competitive factor.

Electric Load Management

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



BGE
generally activates these programs on summer days when demand and/or wholesale prices are relatively high. The reduction in the summer 2002 peak load from active load management was
approximately 260 MW.

Transmission and Distribution Facilities

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

We
discuss FERC's initiatives in implementing a standard market design for wholesale electric markets in more detail inItem 7. Management's Discussion and
AnalysisFERC Regulationsection.

---

Electric Operating Statistics

|                        |                   | 2002         |   | 2001    |         | 2000(A) |         | 1999(A) |   | 1998(A)
|----------------------- | ----------------- | ------------ | - | ------- | ------- | ------- | ------- | ------- | - | -------
|
|Revenues(In millions)   |                   |              |   |         |         |         |         |         |   |        
|                        | Residential       |              | $ | 946.6   |         | $       | 885.3   |         | $ | 922.6  
|                        | Commercial        |              |   | 809.5   |         |         | 903.0   |         |   | 926.2  
|                        | Industrial        |              |   | 169.6   |         |         | 218.1   |         |   | 203.6  
|                       
|                        |                   | System Sales |   |         | 1,925.7 |         |         | 2,006.4 |   |        
|                        | Interchange Sales |              |   |        |         |         |        |         |   | 53.8   
|                        | Other (B)         |              |   | 40.3    |         |         | 33.6    |         |   | 29.0   
|                       
|                        |                   | Total        |   | $       | 1,966.0 |         | $       | 2,040.0 |   | $      
|                       
|Sales(In thousands)MWH |                   |              |   |         |         |         |         |         |   |        
|                        | Residential       |              |   | 12,652  |         |         | 11,714  |         |   | 11,675 
|                        | Commercial        |              |   | 14,602  |         |         | 14,147  |         |   | 14,042 
|                        | Industrial        |              |   | 4,475   |         |         | 4,445   |         |   | 4,476  
|                       
|                        |                   | System Sales |   |         | 31,729  |         |         | 30,306  |   |        
|                       
|Customers(In thousands) |                   |              |   |         |         |         |         |         |   |        
|                        | Residential       |              |   | 1,052.3 |         |         | 1,040.5 |         |   | 1,033.4
|                        | Commercial        |              |   | 110.8   |         |         | 110.9   |         |   | 108.9  
|                        | Industrial        |              |   | 4.9     |         |         | 5.0     |         |   | 5.0    
|                       
|                        |                   | Total        |   |         | 1,168.0 |         |         | 1,156.4 |   |        
|                       



Operating statistics do not reflect the elimination of intercompany transactions.

10

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Gas Business

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

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

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

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

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

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

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

Our
current maximum storage entitlements are 235,080 DTH per day. To supplement our gas supply at times of heavy winter demands and to be available in temporary emergencies affecting gas
supply, we have:



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

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

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

11

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Gas Operating Statistics

|                        |                  | 2002                       |              | 2001   |        | 2000    |        | 1999   |         | 1998  
|----------------------- | ---------------- | -------------------------- | ------------ | ------ | ------ | ------- | ------ | ------ | ------- | ------
|
|Revenues(In millions)   |                  |                            |              |        |        |         |        |        |         |       
|                        | Residential      |                            |              |        |        |         |        |        |         |       
|                        |                  | Excluding Delivery Service |              | $      | 342.1  |         | $      | 378.4  |         | $     
|                        |                  | Delivery Service           |              |        | 16.5   |         |        | 16.3   |         |       
|                        | Commercial       |                            |              |        |        |         |        |        |         |       
|                        |                  | Excluding Delivery Service |              |        | 89.4   |         |        | 115.5  |         |       
|                        |                  | Delivery Service           |              |        | 29.2   |         |        | 21.4   |         |       
|                        | Industrial       |                            |              |        |        |         |        |        |         |       
|                        |                  | Excluding Delivery Service |              |        | 9.3    |         |        | 12.8   |         |       
|                        |                  | Delivery Service           |              |        | 13.9   |         |        | 13.8   |         |       
|                       
|                        |                  |                            | System Sales |        |        | 500.4   |        |        | 558.2   |       
|                        | Off-system Sales |                            |              | 74.8   |        |         | 113.6  |        |         | 101.0 
|                        | Other            |                            |              | 6.1    |        |         | 8.9    |        |         | 7.8   
|                       
|                        |                  |                            | Total        |        | $      | 581.3   |        | $      | 680.7   |       
|                       
|Sales(In thousands)DTH |                  |                            |              |        |        |         |        |        |         |       
|                        | Residential      |                            |              |        |        |         |        |        |         |       
|                        |                  | Excluding Delivery Service |              |        | 35,364 |         |        | 33,147 |         |       
|                        |                  | Delivery Service           |              |        | 6,404  |         |        | 7,201  |         |       
|                        | Commercial       |                            |              |        |        |         |        |        |         |       
|                        |                  | Excluding Delivery Service |              |        | 11,583 |         |        | 12,334 |         |       
|                        |                  | Delivery Service           |              |        | 28,429 |         |        | 25,037 |         |       
|                        | Industrial       |                            |              |        |        |         |        |        |         |       
|                        |                  | Excluding Delivery Service |              |        | 1,207  |         |        | 1,386  |         |       
|                        |                  | Delivery Service           |              |        | 23,689 |         |        | 23,872 |         |       
|                       
|                        |                  |                            | System Sales |        |        | 106,676 |        |        | 102,977 |       
|                        | Off-system Sales |                            |              | 18,551 |        |         | 20,012 |        |         | 22,456
|                       
|                        |                  |                            | Total        |        |        | 125,227 |        |        | 122,989 |       
|                       
|Customers(In thousands) |                  |                            |              |        |        |         |        |        |         |       
|                        | Residential      |                            |              | 567.3  |        |         | 558.7  |        |         | 553.7 
|                        | Commercial       |                            |              | 40.7   |        |         | 40.2   |        |         | 40.1  
|                        | Industrial       |                            |              | 1.3    |        |         | 1.4    |        |         | 1.4   
|                       
|                        |                  |                            | Total        |        |        | 609.3   |        |        | 600.3   |       
|                       

Operating statistics do not reflect the elimination of intercompany transactions.

12

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Franchises

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

---

Other Nonregulated Businesses

Energy Products and Services

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



Home Products and Electric and Gas Retail Marketing

We offer services to customers including:



District Cooling Services

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

Other

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

---

Consolidated Capital Requirements

Our business requires a great deal of capital. Our total capital requirements for 2002 were $923 million. Of this amount, $706 million was used in our
nonregulated businesses and $217 million was used in our utility operations. We estimate our total capital requirements to be $735 million in 2003.

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

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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 $265 million during the five-year period 1998-2002 to comply with existing
environmental standards and regulations, and we estimate that the future incremental capital expenditures necessary to comply with existing environmental standards and regulations will be
approximately $20 million in 2003.

13

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Clean Air Act

The Clean Air Act affects both existing generating facilities and new projects. The Clean Air Act and many state laws require significant reductions in SO2 (sulfur
dioxide) and NOX (nitrogen oxide) emissions that result from burning fossil fuels. The Clean Air Act also contains other provisions that could materially affect some of our projects.
Various provisions may require permits, inspections, or installation of additional pollution control technology 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 (a precursor
of ozone). Among other things, the EPA's rule establishes an ozone season, which runs from May through September, and a NOX emission budget for each state, including Maryland and
Pennsylvania. The EPA rule requires states to implement controls sufficient to meet their NOX budget by May 30, 2004. Coal-fired power plants are a principal target of NOX
reductions under this initiative.

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 to meet Maryland regulations issued pursuant to EPA's rule. The owners of the Keystone plant in Pennsylvania are installing emissions
reduction equipment by July 2003 to meet Pennsylvania regulations issued
pursuant to EPA's rule. We estimate our costs for the equipment needed at this plant will be approximately $35 million. Through December 31, 2002, we have spent approximately $26 million.

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

The
EPA and several states have filed suits against a number of coal-fired power plants in Mid-Western and Southern states alleging violations of the deterioration prevention and
non-attainment provisions of the Clean Air Act's new source review requirements. In 2000, and again in 2002, using its broad investigatory powers, the EPA requested information relating to
modifications made to our Brandon Shores, Crane, and Wagner plants in Baltimore, Maryland. The EPA also sent similar, but narrower, information requests to two of our newer Pennsylvania waste-coal
burning plants. This information is to determine compliance with the Clean Air Act and state implementation plan requirements, including potential application of federal New Source Performance
Standards. We have responded to the EPA and as of the date of this report the EPA has taken no further action.

In
general, such standards can require the installation of additional air pollution control equipment upon the major modification of an existing plant. Although there have not been any
new source review-related suits filed against our facilities, there can be no assurance that any of them will not be the target of an action in the future. Based on the levels of emissions control
that the EPA and states are seeking in these new source review enforcement actions, we believe that material additional costs and penalties could be incurred, and planned capital expenditures could be
accelerated, if the EPA was successful in any future actions regarding our facilities.

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

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

14

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Clean Water Act

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

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

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

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

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

Metal Bank

In the early 1970s, BGE shipped an unknown number of scrapped transformers to Metal Bank of America, a metal reclaimer in Philadelphia. Metal Bank's scrap and storage yard has
been found to be contaminated with oil containing high levels of PCBs (hazardous chemicals frequently used as a fire resistant coolant in electrical equipment). On December 7, 1987, the EPA notified
BGE and nine other utilities that they are considered potentially responsible parties (PRPs) with respect to the cleanup of the site. BGE, along with the other PRPs, submitted a remedial investigation
and feasibility study to the EPA on October 14, 1994, and the EPA issued its Record of Decision on December 31, 1997. On June 26, 1998, the EPA ordered BGE, the other utility PRPs, and the
owner/operator to implement the requirements of the Record of Decision. The utility PRPs have submitted the remedial design to EPA. Based on the Record of Decision, BGE's share of the reasonably
possible cleanup costs, estimated to be approximately 15.47%, could be as much as $1.3 million higher than amounts we believe are probable and have recorded as a liability in our Consolidated Balance
Sheets. There has been no significant activity with respect to this site since the EPA's Record of Decision in 1997.

Kane and Lombard Streets

Suit was originally filed by the EPA under CERCLA in October 1989 against BGE and several other defendants in the U.S. District Court for the District of Maryland, seeking to
recover past and future clean up costs at the Kane and Lombard Street site located in Baltimore City, Maryland. The State of Maryland filed a similar complaint in the same case and court in February
1990. The complaints alleged that BGE arranged for coal fly ash to be deposited on the site. The Court dismissed these complaints in November 1995. Maryland began additional investigation on the
remainder of the site for the EPA, but never completed the investigation. BGE, along with three other defendants, agreed to complete a remedial investigation and feasibility study of groundwater
contamination around the site in a July 1993 consent order. The remedial investigation report and a draft feasibility study were submitted to the EPA in
February 2002. In December 2002, the EPA released its proposed remedy for the site and estimated the total cost for the site to be $6.2 million. Until the EPA finalizes the plan, we cannot estimate
BGE's share of the total site cleanup costs, but it is not expected to be material.

68th Street Dump

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

15

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Spring Gardens

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

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

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

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

Employees

Constellation Energy and its subsidiaries had, at December 31, 2002, approximately 8,700 employees. The Central Wayne plant has a partially unionized workforce where
approximately 30 employees are represented by the International Union of Operating Engineers. The labor contract with this union expires June 30, 2004. At the Nine Mile Point plant, approximately 700
employees are represented by the International Brotherhood of Electrical Workers, Local 97. The labor contract with this union expires in July 2006 with wages open to negotiation in June 2003. We
believe that our relations with both unions are satisfactory, but there can be no assurances that this will continue to be the case.

We
discuss several workforce reduction programs inItem 7. Management's Discussion and AnalysisSignificant Eventssection.

---

Item 2. Properties

Constellation Energy's corporate offices occupy approximately 85,000 square feet of leased office space in Baltimore, Maryland. The corporate offices for most of our merchant
energy business occupy approximately 100,000 square feet of leased office space in another building in Baltimore, Maryland. We describe our electric generation properties on the next page. We also
have leases for other offices and services located in the Baltimore metropolitan region, and for various real property and facilities relating to our generation projects.

We
own BGE's principal headquarters building in downtown Baltimore. BGE owns propane air and liquefied natural gas facilities as discussed inItem 1.
BusinessGas Businesssection.

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

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



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

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

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

16

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The following table describes our generating facilities:

|Plant                                       |                        | Location |                                | Installed
Capacity (MW) |       | % Owned |       | Capacity
Owned (MW) |       | Primary
Fuel
|------------------------------------------- | ---------------------- | -------- | ------------------------------ | ----------------------- | ----- | ------- | ----- | ------------------- | ----- | ------------
|
|PJM Platform                                |                        |          |                                |                         |       |         |       |                     |       |             
|                                            | Calvert Cliffs         |          | Calvert Co., MD                |                         | 1,685 |         | 100.0 |                     | 1,685 |             
|                                            | Brandon Shores         |          | Anne Arundel Co., MD           |                         | 1,286 |         | 100.0 |                     | 1,286 |             
|                                            | H. A. Wagner           |          | Anne Arundel Co., MD           |                         | 1,020 |         | 100.0 |                     | 1,020 |             
|                                            | C. P. Crane            |          | Baltimore Co., MD              |                         | 399   |         | 100.0 |                     | 399   |             
|                                            | Keystone               |          | Armstrong and Indiana Cos., PA |                         | 1,711 |         | 21.0  |                     | 359   | (A)         
|                                            | Conemaugh              |          | Indiana Co., PA                |                         | 1,711 |         | 10.6  |                     | 181   | (A)         
|                                            | Perryman               |          | Harford Co., MD                |                         | 360   |         | 100.0 |                     | 360   |             
|                                            | Riverside              |          | Baltimore Co., MD              |                         | 251   |         | 100.0 |                     | 251   |             
|                                            | Handsome Lake          |          | Rockland Twp, PA               |                         | 250   |         | 100.0 |                     | 250   |             
|                                            | Notch Cliff            |          | Baltimore Co., MD              |                         | 128   |         | 100.0 |                     | 128   |             
|                                            | Westport               |          | Baltimore City, MD             |                         | 121   |         | 100.0 |                     | 121   |             
|                                            | Gould Street           |          | Baltimore City, MD             |                         | 104   |         | 100.0 |                     | 104   |             
|                                            | Philadelphia Road      |          | Baltimore City, MD             |                         | 64    |         | 100.0 |                     | 64    |             
|                                            | Safe Harbor            |          | Safe Harbor, PA                |                         | 416   |         | 66.7  |                     | 277   |             
|                                            |                        |          |                                |                         |       |         |       |                     |       |             
|Total PJM Platform                          |                        |          |                                | 9,506                   |       |         |       | 6,485               |       |             
|Plants with Power Purchase Agreements       |                        |          |                                |                         |       |         |       |                    
|                                            | Nine Mile Point Unit 1 |          | Scriba, NY                     |                         | 609   |         | 100.0 |                     | 609   |             
|                                            | Nine Mile Point Unit 2 |          | Scriba, NY                     |                         | 1,148 |         | 82.0  |                     | 941   |             
|                                            | Oleander               |          | Brevard Co., FL                |                         | 680   |         | 100.0 |                     | 680   |             
|                                            | University Park        |          | Chicago, IL                    |                         | 300   |         | 100.0 |                     | 300   |             
|                                            |                        |          |                                |                         |       |         |       |                     |       |             
|Total Plants with Power Purchase Agreements |                        | 2,737    |                                |                         |       | 2,530   |       |                    
|Competitive Supply                          |                        |          |                                |                         |       |         |       |                     |       |             
|                                            | Rio Nogales            |          | Seguin, TX                     |                         | 800   |         | 100.0 |                     | 800   |             
|Other                                       |                        |          |                                |                         |       |         |       |                     |       |             
|                                            | Holland Energy         |          | Shelby Co., IL                 |                         | 665   |         | 100.0 |                     | 665   |             
|                                            | Big Sandy              |          | Neal, WV                       |                         | 300   |         | 100.0 |                     | 300   |             
|                                            | Wolf Hills             |          | Bristol, VA                    |                         | 250   |         | 100.0 |                     | 250   |             
|                                            | Panther Creek          |          | Nesquehoning, PA               |                         | 83    |         | 50.0  |                     | 42    |             
|                                            | Colver                 |          | Colver Township, PA            |                         | 110   |         | 25.0  |                     | 28    |             
|                                            | Sunnyside              |          | Sunnyside, UT                  |                         | 53    |         | 50.0  |                     | 26    |             
|                                            | ACE                    |          | Trona, CA                      |                         | 102   |         | 30.3  |                     | 31    |             
|                                            | Jasmin                 |          | Kern Co., CA                   |                         | 33    |         | 50.0  |                     | 17    |             
|                                            | POSO                   |          | Kern Co., CA                   |                         | 33    |         | 50.0  |                     | 17    |             
|                                            | Puna I                 |          | Hilo, HI                       |                         | 30    |         | 50.0  |                     | 15    |             
|                                            | Mammoth Lakes G-1      |          | Mammoth Lakes, CA              |                         | 8     |         | 50.0  |                     | 4     |             
|                                            | Mammoth Lakes G-2      |          | Mammoth Lakes, CA              |                         | 12    |         | 50.0  |                     | 6     |             
|                                            | Mammoth Lakes G-3      |          | Mammoth Lakes, CA              |                         | 12    |         | 50.0  |                     | 6     |             
|                                            | Soda Lake I            |          | Fallon, NV                     |                         | 3     |         | 50.0  |                     | 2     |             
|                                            | Soda Lake II           |          | Fallon, NV                     |                         | 13    |         | 50.0  |                     | 7     |             
|                                            | Stillwater             |          | Fallon, NV                     |                         | 13    |         | 50.0  |                     | 6     |             
|                                            | Rocklin                |          | Placer Co., CA                 |                         | 24    |         | 50.0  |                     | 12    |             
|                                            | Fresno                 |          | Fresno, CA                     |                         | 24    |         | 50.0  |                     | 12    |             
|                                            | Chinese Station        |          | Sonora, CA                     |                         | 22    |         | 45.0  |                     | 10    |             
|                                            | Malacha                |          | Muck Valley, CA                |                         | 32    |         | 50.0  |                     | 16    |             
|                                            | Central Wayne          |          | Dearborn, MI                   |                         | 22    |         | 50.0  |                     | 11    |             
|                                            | SEGS IV                |          | Kramer Junction, CA            |                         | 30    |         | 12.0  |                     | 4     |             
|                                            | SEGS V                 |          | Kramer Junction, CA            |                         | 30    |         | 4.0   |                     | 1     |             
|                                            | SEGS VI                |          | Kramer Junction, CA            |                         | 30    |         | 9.0   |                     | 3     |             
|                                            |                        |          |                                |                         |       |         |       |                     |       |             
|Total Other                                 |                        |          |                                | 1,934                   |       |         |       | 1,491               |       |             
|                                            |                        |          |                                |                         |       |         |       |                     |       |             
|Total Generating Facilities                 |                        |          |                                | 14,977                  |       |         |       | 11,306              |       |             
|                                            |                        |          |                                |                         |       |         |       |                     |       |             

17

---

The following table describes our processing facilities:

|Plant             |  | Location         |  | Installed
Capacity (MW) |  | % Owned |  | Capacity
Owned (MW) |  | Primary
Fuel      
|----------------- |  | ---------------- |  | ----------------------- |  | ------- |  | ------------------- |  | ------------------
|
|A/C Fuels         |  | Hazelton, PA     |  |                        |  | 50.0    |  |                    |  | Coal Processing   
|Gary PCI          |  | Gary, IN         |  |                        |  | 24.5    |  |                    |  | Coal Processing   
|PC Synfuel VA I   |  | Appalachia, VA   |  |                        |  | 16.7    |  |                    |  | Synfuel Processing
|PC Synfuel WV I   |  | Charleston, WV   |  |                        |  | 16.7    |  |                    |  | Synfuel Processing
|PC Synfuel WV II  |  | 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 inItem 7. Management's Discussion and AnalysisBusiness Environmentsection and in Note 11 to Consolidated Financial
Statements.

---

Item 4. Submission of Matters to Vote of Security Holders

Not applicable.

Executive Officers of the Registrant

|Name                 |  | Age |  | Present Office                                                                                                                                                                                               |  | Other Offices or Positions Held
During Past Five Years                                                                                                                                                                                                           
|-------------------- |  | --- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Mayo A. Shattuck III |  | 48  |  | 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      |  | 43  |  | Senior Vice President and Chief Financial Officer of Constellation Energy (since June 2001) and Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company (since January 2002) |  | 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     |  | 40  |  | President of Constellation Power Source, Inc. (since October 2001)                                                                                                                                           |  | Vice President of Business Development and StrategyConstellation Energy; and Vice PresidentGoldman Sachs.                                                                                                                                                      
|Frank O. Heintz      |  | 59  |  | President and Chief Executive Officer of Baltimore Gas and Electric Company (since July 2000)                                                                                                                |  | Executive Vice President, Utility OperationsBGE; and Vice President, GasBGE.                                                                                                                                                                                   
|Michael J. Wallace   |  | 55  |  | President of Constellation Generation Group, LLC (since January 2002)                                                                                                                                        |  | Managing Director and MemberBarrington Energy Partners; and Senior Vice PresidentCommonwealth Edison.                                                                                                                                                          
|Thomas F. Brady      |  | 53  |  | Senior Vice President, Corporate Strategy and Development of Constellation Energy (since May 2002)                                                                                                           |  | Vice President, Corporate Strategy and DevelopmentConstellation Energy; Vice President, Retail ServicesBGE; and Vice President, Customer Service and DistributionBGE.                                                                                         
|                     |  |     |  |                                                                                                                                                                                                              |  |                                                                                                                                                                                                                                                                  

18

---

|Paul J. Allen       |  | 51 |  | Vice President, Corporate Affairs of Constellation Energy (since May 2001)                  |  | Senior Vice President and Group HeadOgilvy Public Relations.                                                                                            
|------------------- |  | -- |  | ------------------------------------------------------------------------------------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------
|Kathleen A. Chagnon |  | 43 |  | Vice President, General Counsel, and Secretary of Constellation Energy (since August 2002)  |  | Vice President, Corporate Group General CounselThe St. Paul Companies, Inc.; and Assistant Vice President and Associate Group CounselUSF&G Corporation.
|John R. Collins     |  | 45 |  | Vice President and Chief Risk Officer of Constellation Energy (since December 2001)         |  | Managing DirectorFinanceConstellation Power Source Holdings, Inc.; and Senior Financial OfficerConstellation Power Source, Inc.                       
|Mark P. Huston      |  | 39 |  | Vice President, Corporate Strategy and Development of Constellation Energy (since May 2002) |  | Manager, Corporate Strategy & DevelopmentConstellation Energy; Project Manager, Restructuring ProjectBGE; and Director, Gas Business DevelopmentBGE.  
|Marc C. Ugol        |  | 44 |  | Vice President, Human Resources of Constellation Energy (since October 2002)                |  | 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.

19

---

PART II

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

Stock Trading

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

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

Dividend Policy

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

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

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

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

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



---

Common Stock Dividends and Price Ranges

|               |  | 2002 |     | 2001
|-------------- |  | ---- | --- | ----
|
|
|
|First Quarter  |  | $    | .24 |     
|Second Quarter |  |      | .24 |     
|Third Quarter  |  |      | .24 |     
|Fourth Quarter |  |      | .24 |     
|               |  |      |     |     
|Total          |  | $    | .96 |     
|               |  |      |     |     

*
Based on New York Stock Exchange Composite Transactions.

20

---



Item 6. Selected Financial Data

Constellation Energy Group, Inc. and Subsidiaries

|                                 |                                                                                          | 2002                                                                                                                          |   | 2001     |         | 2000 |          | 1999    |   | 1998    
|-------------------------------- | ---------------------------------------------------------------------------------------- | ----------------------------------------------------------------------------------------------------------------------------- | - | -------- | ------- | ---- | -------- | ------- | - | --------
|
|
|Summary of Operations            |                                                                                          |                                                                                                                               |   |          |         |      |          |         |   |         
|                                 | Total Revenues                                                                           |                                                                                                                               | $ | 4,703.0  |         | $    | 3,878.8  |         | $ | 3,774.4 
|                                 | Total Expenses                                                                           |                                                                                                                               |   | 3,878.1  |         |      | 3,527.2  |         |   | 3,009.9 
|                                 | Net Gain on Sales of Investments and Other Assets                                        |                                                                                                                               |   | 261.3    |         |      | 6.2      |         |   | 78.1    
|                                
|                                 | Income From Operations                                                                   |                                                                                                                               |   | 1,086.2  |         |      | 357.8    |         |   | 842.6   
|                                 | Other Income                                                                             |                                                                                                                               |   | 30.5     |         |      | 1.3      |         |   | 4.2     
|                                 | Fixed Charges                                                                            |                                                                                                                               |   | 281.5    |         |      | 238.8    |         |   | 271.4   
|                                
|                                 | Income Before Income Taxes                                                               |                                                                                                                               |   | 835.2    |         |      | 120.3    |         |   | 575.4   
|                                 | Income Taxes                                                                             |                                                                                                                               |   | 309.6    |         |      | 37.9     |         |   | 230.1   
|                                
|                                 | Income Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle |                                                                                                                               |   | 525.6    |         |      | 82.4     |         |   | 345.3   
|                                 | Extraordinary Loss, Net of Income Taxes                                                  |                                                                                                                               |   |         |         |      |         |         |   |        
|                                 | Cumulative Effect of Change in Accounting Principle, Net of Income Taxes                 |                                                                                                                               |   |         |         |      | 8.5      |         |   |        
|                                
|                                 | Net Income                                                                               |                                                                                                                               | $ | 525.6    |         | $    | 90.9     |         | $ | 345.3   
|                                
|                                 | Earnings Per Common Share and                                                            |                                                                                                                               |   |          |         |      |          |         |   |         
|                                 |                                                                                          | Earnings Per Common ShareAssuming Dilution Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle |   | $        | 3.20    |      | $        | .52     |   | $       
|                                 | Extraordinary Loss                                                                       |                                                                                                                               |   |         |         |      |         |         |   |        
|                                 | Cumulative Effect of Change in Accounting Principle                                      |                                                                                                                               |   |         |         |      | .05      |         |   |        
|                                
|                                 | Earnings Per Common Share and                                                            |                                                                                                                               |   |          |         |      |          |         |   |         
|                                 |                                                                                          | Earnings Per Common ShareAssuming Dilution                                                                                   |   | $        | 3.20    |      | $        | .57     |   | $       
|                                
|                                 | Dividends Declared Per Common Share                                                      |                                                                                                                               | $ | .96      |         | $    | .48      |         | $ | 1.68    
|                                
|Summary of Financial Condition   |                                                                                          |                                                                                                                               |   |          |         |      |          |         |   |         
|                                 | Total Assets                                                                             |                                                                                                                               | $ | 14,128.9 |         | $    | 14,109.4 |         | $ | 12,939.3
|                                
|                                 | Short-Term Borrowings                                                                    |                                                                                                                               | $ | 10.5     |         | $    | 975.0    |         | $ | 243.6   
|                                
|                                 | Current Portion of Long-Term Debt                                                        |                                                                                                                               | $ | 426.2    |         | $    | 1,406.7  |         | $ | 906.6   
|                                
|                                 | Capitalization                                                                           |                                                                                                                               |   |          |         |      |          |         |   |         
|                                 |                                                                                          | Long-Term Debt                                                                                                                |   | $        | 4,613.9 |      | $        | 2,712.5 |   | $       
|                                 |                                                                                          | Minority Interests                                                                                                            |   |          | 105.3   |      |          | 101.7   |   |         
|                                 |                                                                                          | Preference Stock Not Subject to Mandatory Redemption                                                                          |   |          | 190.0   |      |          | 190.0   |   |         
|                                 |                                                                                          | Common Shareholders' Equity                                                                                                   |   |          | 3,862.3 |      |          | 3,843.6 |   |         
|                                
|                                 | Total Capitalization                                                                     |                                                                                                                               | $ | 8,771.5  |         | $    | 6,847.8  |         | $ | 6,621.0 
|                                
|Financial Statistics at Year End |                                                                                          |                                                                                                                               |   |          |         |      |          |         |   |         
|                                 | Ratio of Earnings to Fixed Charges                                                       |                                                                                                                               |   | 3.33     |         |      | 1.18     |         |   | 2.78    
|                                 | Book Value Per Share of Common Stock                                                     |                                                                                                                               | $ | 23.44    |         | $    | 23.48    |         | $ | 21.09   

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, and special items, inItem 7. Management's Discussion and
Analysis.

21

---

Baltimore Gas and Electric Company and Subsidiaries

|                                 |                                                                                 | 2002                                                 |   | 2001    |         | 2000(A) |         | 1999    |   | 1998   
|-------------------------------- | ------------------------------------------------------------------------------- | ---------------------------------------------------- | - | ------- | ------- | ------- | ------- | ------- | - | -------
|
|
|Summary of Operations            |                                                                                 |                                                      |   |         |         |         |         |         |   |        
|                                 | Total Revenues                                                                  |                                                      | $ | 2,547.3 |         | $       | 2,720.7 |         | $ | 2,746.8
|                                 | Total Expenses                                                                  |                                                      |   | 2,181.0 |         |         | 2,408.9 |         |   | 2,334.4
|                                
|                                 | Income From Operations                                                          |                                                      |   | 366.3   |         |         | 311.8   |         |   | 412.4  
|                                 | Other Income                                                                    |                                                      |   | 10.7    |         |         | 0.4     |         |   | 7.5    
|                                 | Fixed Charges                                                                   |                                                      |   | 140.6   |         |         | 154.6   |         |   | 184.0  
|                                
|                                 | Income Before Income Taxes                                                      |                                                      |   | 236.4   |         |         | 157.6   |         |   | 235.9  
|                                 | Income Taxes                                                                    |                                                      |   | 93.3    |         |         | 60.3    |         |   | 92.4   
|                                
|                                 | Income Before Extraordinary Item                                                |                                                      |   | 143.1   |         |         | 97.3    |         |   | 143.5  
|                                 | Extraordinary Loss, Net of Income Taxes                                         |                                                      |   |        |         |         |        |         |   |       
|                                
|                                 | Net Income                                                                      |                                                      |   | 143.1   |         |         | 97.3    |         |   | 143.5  
|                                 | Preference Stock Dividends                                                      |                                                      |   | 13.2    |         |         | 13.2    |         |   | 13.2   
|                                
|                                 | Earnings Applicable to Common Stock                                             |                                                      | $ | 129.9   |         | $       | 84.1    |         | $ | 130.3  
|                                
|Summary of Financial Condition   |                                                                                 |                                                      |   |         |         |         |         |         |   |        
|                                 | Total Assets                                                                    |                                                      | $ | 4,779.9 |         | $       | 4,954.5 |         | $ | 4,654.2
|                                
|                                 | Short-Term Borrowings                                                           |                                                      | $ |        |         | $       |        |         | $ | 32.1   
|                                
|                                 | Current Portion of Long-Term Debt                                               |                                                      | $ | 420.7   |         | $       | 666.3   |         | $ | 567.6  
|                                
|                                 | Capitalization                                                                  |                                                      |   |         |         |         |         |         |   |        
|                                 |                                                                                 | Long-Term Debt                                       |   | $       | 1,499.1 |         | $       | 1,821.7 |   | $      
|                                 |                                                                                 | Minority Interest                                    |   |         | 19.4    |         |         | 5.0     |   |        
|                                 |                                                                                 | Preference Stock Not Subject to Mandatory Redemption |   |         | 190.0   |         |         | 190.0   |   |        
|                                 |                                                                                 | Common Shareholder's Equity                          |   |         | 1,461.7 |         |         | 1,131.4 |   |        
|                                
|                                 | Total Capitalization                                                            |                                                      | $ | 3,170.2 |         | $       | 3,148.1 |         | $ | 2,861.3
|                                
|Financial Statistics at Year End |                                                                                 |                                                      |   |         |         |         |         |         |   |        
|                                 | Ratio of Earnings to Fixed Charges                                              |                                                      |   | 2.66    |         |         | 1.99    |         |   | 2.27   
|                                 | Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends |                                                      |   | 2.31    |         |         | 1.75    |         |   | 2.03   

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

22

---



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

Introduction

Constellation Energy Group, Inc. (Constellation Energy) is a North American energy company that conducts its business through various subsidiaries including a
merchant energy business and Baltimore Gas and Electric Company (BGE). We describe our operating segments inNote 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 customers, such as utilities, municipalities, cooperatives, retail aggregators, and large 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.

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

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. We sold certain non-core assets in 2002 and closed our retail merchandise stores in December 2002.

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



As
you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2002, 2001, and 2000. We analyze and explain the
differences between periods in the specific line items of the Consolidated Statements of Income.

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

Critical Accounting Policies

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



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

Management
believes the following accounting policies represent critical accounting policies as defined by the SEC. 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. We discuss our significant accounting policies, including those that do not require management to make
difficult, subjective, or complex judgments or estimates, inNote 1.

Revenue Recognition/Mark-to-Market Method of Accounting

Our merchant energy business engages in origination and risk management activities using contracts for energy, other energy-related commodities, and related derivative
contracts. 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 in more detail in Note 1.

23

---

On
October 25, 2002, the Emerging Issues Task Force (EITF) reached a consensus on Issue 02-3,Recognition and Reporting of Gains and Losses on Energy Trading
Contracts Under EITF Issues No. 98-10 and No. 00-17. EITF 02-3 affects how we apply the mark-to-market method of accounting. We describe our accounting for energy contracts and
the impact of EITF 02-3 below.

We
use mark-to-market accounting for energy trading activities and for derivatives and other contracts for which we are not permitted to use accrual accounting or hedge accounting. These
mark-to-market activities include derivative and (prior to EITF 02-3) non-derivative contracts for energy and other energy-related commodities. Under the mark-to-market method of accounting, we record
the fair value of energy contracts 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.

At
December 31, 2002, mark-to-market energy assets and liabilities consisted of a combination of energy and energy-related derivative and non-derivative contracts. While some of these
contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using modeling
techniques to determine expected future market prices, contract quantities, or both. The market prices 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 fair value that are 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 risks 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.



Market
prices for energy and energy-related commodities vary based upon a number of factors. Changes in market prices will 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. 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 Risksection.

On
October 25, 2002, the EITF reached a consensus on Issue 02-3 that changed the accounting for certain energy contracts. The main provisions of Issue 02-3 are as follows:



24

---



Applying
EITF 02-3 will not affect our cash flows or our accounting for new load-serving contracts for which we have been using accrual accounting since early 2002. Additionally, we
continued to mark existing non-derivative energy-related contracts to market for the remainder of 2002. However, EITF 02-3 requires us to record a non-cash, cumulative effect adjustment to
convert these non-derivative mark-to-market contracts to accrual accounting no later than January 1, 2003.

We
reviewed our portfolio of mark-to-market contracts to identify the contracts that are subject to the requirements of EITF 02-3. The primary contracts that are affected are our full
requirements load-serving contracts and unit-contingent power purchase contracts, which are not derivatives. The majority of these contracts are in Texas and New England and were entered
into prior to the shift to accrual accounting earlier in 2002. Additionally, we reviewed derivatives we use as supply sources and hedges of contracts that are subject to EITF 02-3. To the extent
permitted by Statement of Financial Accounting Standards (SFAS) No. 133,Accounting for Derivative Instruments and Hedging Activities,as amended, we
designated derivative contracts used to fulfill our load-serving contracts as either normal purchases or cash flow hedges under SFAS No. 133 effective January 1, 2003.

We
summarize the impact on our Consolidated Balance Sheets of applying EITF 02-3 on January 1, 2003 as follows:

|                                                                                                 |                                 | Assets |         | Liabilities |   | Net     |       
|------------------------------------------------------------------------------------------------ | ------------------------------- | ------ | ------- | ----------- | - | ------- | ------
|
|
|Mark-to-market energy contracts                                                                  |                                 |        |         |             |   |         |       
|                                                                                                 | Current                         |        | $       | 144.0       |   | $       | 94.1  
|                                                                                                 | Noncurrent                      |        |         | 1,348.2     |   |         | 881.5 
|                                                                                                 |                                
|                                                                                                 | Total                           |        |         | 1,492.2     |   |         | 975.6 
|Other                                                                                            |                                 |        |         |             |   |         |       
|                                                                                                 | Current                         |        |         | 85.7        |   |         | 56.8  
|                                                                                                 | Noncurrent                      |        |         | 24.2        |   |         | 2.5   
|                                                                                                 |                                
|                                                                                                 | Total                           |        |         | 109.9       |   |         | 59.3  
|                                                                                                 |                                
|Balance at December 31, 2002                                                                     |                                 |        | 1,602.1 |             |   | 1,034.9 |       
|Impact of EITF 02-3 Adoption                                                                     |                                 |        |         |             |   |         |       
|Non-derivative net asset reversed as cumulative effect of a change in accounting principle       |                                 |        |         |             |   |         |       
|                                                                                                 | Mark-to-market energy contracts |        |         | (494.7      | ) |         | (119.8
|                                                                                                 | Other                           |        |         | (109.9      | ) |         | (59.3 
|                                                                                                 |                                
|Total non-derivative net asset reversed as cumulative effect of a change in accounting principle |                                 |        | (604.6  | )           |   | (179.1  | )     
|Derivatives designated as hedges                                                                 |                                 |        | (88.3   | )           |   | (94.4   | )     
|Derivatives designated as normal purchases and sales                                             |                                 |        | (192.6  | )           |   | (128.3  | )     
|                                                                                                 |                                
|Mark-to-market derivatives remaining after adoption of EITF 02-3 on January 1, 2003              |                                 | $      | 716.6   |             | $ | 633.1   |       
|                                                                                                 |                                

On
January 1, 2003, we recorded the $425.5 million non-derivative net asset removed from our Consolidated Balance Sheets as a cumulative effect of a change in accounting principle, which
will reduce our 2003 net income by $263 million. The $425.5 million represents $374.9 million of non-derivative contracts recorded as "Mark-to-market energy assets and liabilities" and $50.6 million
of "Other assets and liabilities" from the re-designation of Texas contracts to accrual accounting earlier in 2002. The fair value of these contracts will be recognized in earnings as power is
delivered.

Additionally,
on January 1, 2003, we reclassified the fair value of derivatives designated as hedges as "Risk management assets and liabilities" in the balance sheet and will account for
these hedges in accordance with the provisions of SFAS No. 133. At that time, we also reclassified the fair value of derivatives designated as normal purchases and normal sales as "Other assets
and liabilities" in the balance sheet and will account for these contracts on the accrual basis, with the fair value amortized into earnings over the lives of the underlying contracts.

We
cannot predict the impact of applying the provisions of EITF 02-3 in the future. Those provisions prohibit mark-to-market accounting for gains at the inception of new non-derivative
energy contracts, require accrual accounting for those contracts, and limit the ability to record gains at the inception of new derivative contracts. We believe that our shift to accrual accounting
for new physical delivery transactions in early 2002 is consistent with the requirement of EITF 02-3 to use accrual accounting for non-derivative contracts.

However,
the impact of applying EITF 02-3 in the future will be affected by many factors, including:



While
we cannot predict the ongoing impact of applying EITF 02-3, the timing of recognizing earnings on new transactions will change. In general, earnings on new transactions will no
longer be recognized at the inception of the transactions under mark-to-market accounting because they will be recognized over the term of the transaction. As a result, while total earnings over the
term of a transaction will be unchanged, we expect that our reported earnings for contracts subject to EITF 02-3 will generally match the cash flows from those contracts more closely and may be less
volatile under accrual accounting than under mark-to-market accounting, which reflects changes in fair value of contracts when they occur rather than when products are delivered and costs are
incurred.

25

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Alternatively,
other comprehensive income may have greater fluctuations after we apply EITF 02-3 because of a larger number of derivative contracts that we designated for hedge
accounting under SFAS No. 133, but these fluctuations will not affect earnings or cash flows. Additionally, because we will record revenues and costs on a gross basis under accrual accounting, our
revenues and costs could increase, but our earnings will not be affected by gross versus net reporting.

We discuss the impact of mark-to-market accounting on our financial results in theResults of OperationsMerchant Energy Businesssection.

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

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 would be as follows:



For
long-lived assets that are expected to be held and used, SFAS No. 144 requires 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 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 judgement surrounding the inherent uncertainty of future cash flows.

In
order to estimate an asset's future cash flows, we will 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 establish the cash flows.

We
use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, legislative initiatives, 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 shall be recognized to the extent their carrying amount exceeds
their fair value, including costs to sell.

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 estimation and
judgment. We consider quoted market prices in active markets to the extent they are available. In the absence of such information, we may look to 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 and 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
also are 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.

26

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Significant Events

2002

In 2002, we recorded the following special items in earnings:

|                                                  |                                                                        | Pre-Tax |       | After-Tax |  
|------------------------------------------------- | ---------------------------------------------------------------------- | ------- | ----- | --------- | -
|
|Workforce reduction costs:                        |                                                                        |         |       |           |  
|                                                  | Costs associated with 2001 programs                                    |         | $     | (50.8     | )
|                                                  | Costs associated with programs initiated in 2002                       |         |       | (12.0     | )
|                                                  |                                                                       
|                                                  | Total workforce reduction costs                                        |         |       | (62.8     | )
|Impairment losses and other costs:                |                                                                        |         |       |           |  
|                                                  | Impairments of investments in qualifying facilities and power projects |         |       | (14.4     | )
|                                                  | Costs associated with exit of BGE Home merchandise stores              |         |       | (9.0      | )
|                                                  | Impairments of real estate and international investments               |         |       | (1.8      | )
|                                                  |                                                                       
|                                                  | Total impairment losses and other costs                                |         |       | (25.2     | )
|Net gain on sales of investments and other assets |                                                                        |         | 261.3 |           |  
|                                                  |                                                                       
|Total special items                               |                                                                        | $       | 173.3 |           | $
|                                                  |                                                                       

We
also discuss these special items inNote 2.

Workforce Reduction Costs

During 2002, we incurred costs related to workforce reduction efforts initiated in the fourth quarter of 2001 as discussed in the 2001section and additional initiatives undertaken in
2002. We discuss these costs in more detail below.

Costs Associated with 2001 ProgramsIn 2002, we recorded $63.7 million of net workforce reduction costs associated with our 2001 workforce initiatives as discussed below. The $63.7 million included $50.8 million recognized as expense,
of which BGE recognized $33.8 million. The remaining $12.9 million was recognized by BGE as a regulatory asset related to its gas business.



Costs Associated with 2002 ProgramsIn 2002, we recorded $12.0 million of expenses for anticipated involuntary severance costs in accordance with EITF 94-3,Liability Recognition for Certain Employee Termination
Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)associated with new workforce reduction initiatives as follows:



Ongoing ImpactsAs a result of our workforce reduction programs and other process improvements, we expect to realize cost savings from productivity initiatives of approximately $65 million in 2003.

Impairment Losses and Other Costs

Investments in Qualifying Facilities and Power ProjectsOur merchant energy business recorded impairment losses on certain of the investments in qualifying facilities and power projects totaling $14.4 million under the provisions of APB No. 18. The
provisions of APB No. 18 require that an impairment loss be recognized when an investment experiences a loss in value that is other than temporary as discussed in ourCritical
Accounting Policiessection.

During
the third quarter of 2002, we performed an analysis of whether any of the investments were impaired. As a result of our analysis, we concluded that the declines in value of
particular investments in certain qualifying facilities and power projects were other than temporary in nature under the provisions of APB No. 18 and we recognized the following losses in 2002:



27

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At
December 31, 2002, our investment in qualifying facilities and domestic power projects consisted of the following:

|Project Type    |  | Book Value
|--------------- |  | ----------
|
|Geothermal      |  | $         
|Coal            |  |           
|Hydroelectric   |  |           
|Biomass         |  |           
|Fuel Processing |  |           
|Solar           |  |           
|               
|Total           |  | $         
|               

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 ourForward Looking Statementssection. 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.

We
have an investment in a partnership that owns a geothermal project with a book value of $99.0 million at December 31, 2002. Currently, the project is not generating at its designed
capacity. The project is drilling wells at this site to restore the generation and we expect the geothermal resource to be sufficient to enable the project to generate adequate cash flows over the
life of this project to recover our equity interest in that investment. However, should current or future well drilling at this site prove to be unsuccessful or become uneconomic causing us not to
make future investments in this partnership, our investment in this partnership could become impaired under the provisions of APB No. 18 and any losses recognized 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.

Closing of BGE Home Retail Merchandise StoresIn September 2002, we announced our decision to close our BGE Home retail merchandise stores. In connection with that decision, we recognized approximately $9.5 million in exit costs.
We recognized $2.9 million related to expected severance costs for 93 employees and $2.9 million of costs in connection with the termination of leases for the eight stores and other exit costs in
accordance with EITF 94-3.

We
also recognized $3.2 million for the write-off of unamortized leasehold improvements in accordance with SFAS No. 144, and $0.5 million for the write-down of inventory to a
lower-of-cost-or-market valuation in accordance with Accounting Research Bulletin No. 43,Restatement and Revision of Accounting Research Bulletins. The
$0.5 million is included in "Operating expenses" in our Consolidated Statements of Income.

Real Estate and International InvestmentsAs discussed in the2001section, we changed our strategy from an intent to hold to an intent to sell for certain of our non-core assets in 2001. During
2002, we determined that the fair value of several real estate projects and our investment in a South American generation project declined below their respective book values due to deteriorating
market conditions for these projects. Accordingly, we recorded losses that totaled $1.8 million for these projects in accordance with SFAS No. 144 and APB No. 18. In 2002, we sold our
investment in a South American generation project for approximately book value.

Net Gain on Sales of Investments and Other Assets

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

28

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In
the fourth quarter of 2001, we announced our decision to focus efforts and capital on core domestic energy businesses and undertook a plan to sell a number of non-core businesses and
investments. In 2002, we made further progress on this initiative, and recognized approximately $5.8 million in net gains from the sale of several non-core assets including:



In
addition, we sold all of our Corporate Office Properties Trust (COPT) equity-method investment in 2002, approximately 8.9 million shares, as part of a public offering. We received
cash proceeds of $101.3 million on the sale, which approximated the book value of our investment.

Acquisitions

NewEnergyOn September 9, 2002, we completed our purchase of AES NewEnergy, Inc. from AES Corporation. Subsequent to the acquisition, we renamed AES NewEnergy, Inc. as Constellation NewEnergy, Inc. (NewEnergy).
NewEnergy is a leading national provider of electricity, natural gas, and energy services, serving approximately 4,300 megawatts (MW) of load associated with large commercial and industrial customers
in competitive energy markets including the Northeast, Mid-Atlantic, Midwest, Texas and California. We acquired 100% ownership of NewEnergy for cash of $250.3 million including $1.4 million of direct
costs associated with the acquisition. We acquired cash of $45.5 million as part of the purchase. We describe the net assets acquired inNote 14. We
include the results of NewEnergy in our merchant energy business segment beginning on the date of acquisition.

AllianceOn December 31, 2002, we purchased Alliance Energy Services, LLC and Fellon-McCord Associates, Inc. (collectively, Alliance) from Allegheny Energy, Inc. These businesses provide gas supply and
transportation services and energy consulting services to large commercial and industrial businesses primarily in the Midwest region, but also in other competitive energy markets including the
Northeast, Mid-Atlantic, Texas and California regions. We acquired 100% ownership of these companies for a note payable of $21.2 million that was settled in cash on January 2, 2003. We acquired cash
of $4.6 million as part of the purchase. We describe the net assets acquired inNote 14. We will include the operating results of Alliance in our
merchant energy business segment in 2003.

Renegotiations of our High Desert Power Contract

We are currently leasing and supervising the construction of the High Desert Power Project. The project is scheduled for completion in mid-2003. In April 2002, we amended our
High Desert Power Project long-term power sales agreement with the State of California to provide revised pricing and more flexibility in the amount of electricity purchased from the plant by the
California Department of Water Resources (CDWR) and the timing of such purchases. This amended agreement provides the State of California with the flexibility they desired, while preserving our
overall economics and reducing our regulatory, fuel, and legal risks.

The
contract is a "tolling" structure, under which the CDWR will pay a fixed amount of $12.1 million per month and provides CDWR the right, but not the obligation, to purchase power from
the High Desert Power Project at a price linked to the variable cost of production. During the term of the contract, which runs for seven years and nine months from the commercial operation date of
the plant, the High Desert Power Project will provide energy exclusively to the CDWR.

We
also signed a comprehensive settlement agreement with the CDWR, the California Energy Oversight Board (EOB), the CPUC, the California Attorney General, and the Governor of California
by which each of these parties agreed to release claims against us arising out of the original and renegotiated contracts.

Under
the settlement agreement, the California parties filed with the Federal Energy Regulatory Commission (FERC) to withdraw us from the regulatory complaint filed at the FERC by the
CPUC and EOB against all holders of long-term power contracts. We agreed to pay $1.25 million into a school and public buildings energy retrofit fund and another $1.25 million to the Attorney
General's office in order to conclude this overall comprehensive settlement package.

We
discuss our High Desert project in more detail in theCapital Resourcessection.

29

---

Generating Facilities Commence Operations

The following generating facilities commenced operations during the second half of 2002. Our origination and risk management operation manages the output of these plants.

|Plant          |  | Location        |  | Capacity
(MW) |  | Type               |  | Primary
Fuel
|-------------- |  | --------------- |  | ------------- |  | ------------------ |  | ------------
|Rio Nogales    |  | Seguin, TX      |  | 800           |  | Combined Cycle     |  | Natural Gas 
|Oleander       |  | Brevard Co., FL |  | 680           |  | Combustion Turbine |  | Natural Gas 
|Holland Energy |  | Shelby Co., IL  |  | 665           |  | Combined Cycle     |  | Natural Gas 

Pension Plan

At December 31, 2002, we recorded an after-tax charge to equity of $118 million as a result of increasing our additional minimum pension liability. We discuss this in more
detail inNote 6.

As
a result of declines in the financial markets, our actual return on pension plan assets was a loss of approximately 10% for the year ended December 31, 2002. We assume an expected
return on pension plan assets of 9% for the purpose of computing annual net periodic pension expense. We determined our assumption for expected return on pension plan assets in
accordance with SFAS No. 87,Employers Accounting for Pensions. This assumption reflects our targeted long-term investment allocation of 65% equities
and 35% fixed income securities for our pension plan assets. We set the level of this assumed return based on a review of average, actual returns for these categories of investments over a long-term
period. Some years our actual return on pension assets will exceed the 9% expected return, resulting in an actuarial gain; and some years our actual return will fall short of the 9% expected return,
resulting in an actuarial loss.

These
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 2002, we contributed $152 million to our pension plans, which included $80 million to the
Constellation Energy qualified pension plan and amounts received from the sellers of Nine Mile Point to the Nine Mile Point pension plan. As of the date of this report, we contributed an additional
$111 million to our pension plans in 2003.

Certain Relationships

Thomas F. Brady, a Senior Vice President of Constellation Energy is a trustee of COPT. Constellation Energy sold some of its real estate holdings to COPT in 2002 for an
aggregate price of less than $5 million. Constellation Energy sold, and anticipates selling, additional real estate holdings to COPT in 2003 for an aggregate price of less than $35 million. The real
estate sales were made, and future sales will be made, on an arm's length basis.

2001

In 2001, we recorded the following special items in earnings:

|                                                      |                                                                          | Pre-Tax |        | After-Tax |  
|----------------------------------------------------- | ------------------------------------------------------------------------ | ------- | ------ | --------- | -
|
|Workforce reduction costs:                            |                                                                          |         |        |           |  
|                                                      | Voluntary termination benefitsVSERP                                     |         | $      | (70.1     | )
|                                                      | Settlement and curtailment charges                                       |         |        | (16.3     | )
|                                                      | Involuntary severance accrual                                            |         |        | (19.3     | )
|                                                      |                                                                         
|                                                      | Total workforce reduction costs                                          |         |        | (105.7    | )
|Contract termination related costs                    |                                                                          |         | (224.8 | )         |  
|Impairment losses and other costs:                    |                                                                          |         |        |           |  
|                                                      | Cancellation of domestic power projects                                  |         |        | (46.9     | )
|                                                      | Impairments of real estate, senior-living, and international investments |         |        | (107.3    | )
|                                                      | Reduction of financial investment                                        |         |        | (4.6      | )
|                                                      |                                                                         
|                                                      | Total impairment losses and other costs                                  |         |        | (158.8    | )
|Net gain on the sales of investments and other assets |                                                                          |         | 6.2    |           |  
|                                                      |                                                                         
|Total special items                                   |                                                                          | $       | (483.1 | )         | $
|                                                      |                                                                         

We
also discuss these special items inNote 2.

Workforce Reduction Costs

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

As
a result, we recorded $105.7 million of expenses related to these programs during the fourth quarter of 2001. BGE
recorded $57.0 million of this amount as expense relating to its electric and gas businesses. BGE also recorded $19.5 million on its balance sheet as a regulatory asset of its gas business.

Contract Termination Related Costs

We announced the termination of our power business services agreement with Goldman Sachs & Co. (Goldman Sachs) in 2001. We paid Goldman Sachs a total of $355 million,
representing $196 million to terminate the power business services agreement with our origination and risk management operation and $159 million previously recognized as a payable for services
rendered under the agreement. We issued commercial paper and borrowed under our existing bank lines to fund this payment. In the fourth quarter of 2001, we recognized expenses of approximately $224.8
million related to the termination of the contract with Goldman Sachs.

Impairment Losses and Other Costs

In the fourth quarter of 2001, our merchant energy business recorded impairments of $46.9 million primarily due to the termination of all planned development projects not under
construction, including projects in Texas, California, Florida, and Massachusetts, and due to a decline in value of an investment in

30

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a power project in Michigan. We decided to terminate our development projects due to the expected excess generation capacity in most domestic markets and the significant decline in the forward market
prices of electricity. The impairments included costs associated with four turbines no longer expected to be placed in service.

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



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

Net Gain on the Sales of Investments and Other Assets

During 2001, our other nonregulated businesses recognized a $49.5 million gain on the sale of non-core assets, including a $14.9 million gain on the sale of one million shares
of our Orion investment and $34.6 million on the sales of other financial investments.

In
addition, on November 8, 2001, we sold our Guatemalan power plant operations to an affiliate of Duke Energy International, L.L.C., the international business unit of Duke Energy.
Through this sale, Duke Energy acquired Grupo Generador de Guatemala y Cia., S.C.A., which owns two generating plants at Esquintla and Lake Amatitlan in Guatemala. The combined capacity of the plants
is 167 megawatts.

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

Nine Mile Point

On November 7, 2001, we completed our purchase of the Nine Mile Point Nuclear Station (Nine Mile Point) located in Scriba, New York. Nine Mile Point Nuclear Station, LLC, a
subsidiary of Constellation Nuclear, purchased 100 percent of Nine Mile Point Unit 1 and 82 percent of Unit 2 for cash of $382.7 million including settlement costs and a sellers' note of $388.1
million to be repaid over five years with an interest rate of 11.0%. This note was prepaid in April 2002. The sellers also transferred approximately $442 million in decommissioning funds. As a result
of this purchase, we own 1,550 megawatts of Nine Mile Point's 1,757 megawatts of total generating capacity.

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

We
describe the net assets acquired inNote 14.

Bethlehem Steel

On October 15, 2001, Bethlehem Steel Corporation filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Bethlehem Steel's Sparrows Point plant, located in
Baltimore, Maryland is BGE's largest customer, accounting for approximately three percent of electric revenues and one percent of gas revenues. At December 31, 2002 and 2001, our exposure to Bethlehem
Steel was not material. There is uncertainty regarding the continuation of Bethlehem Steel's operations; however, we do not expect the impact to be material to our financial results.

Strategy

We are pursuing an integrated energy platform that provides a balanced mix of stable and predictable earnings from regulated utility operations with a growth
platform from merchant energy operations. The strategy for our merchant energy business is to be a leading competitive provider of energy solutions for large customers in North America. Our merchant
energy business has electric generation assets located in various regions of the United States and has an origination and risk management operation that focuses on providing energy solutions to meet
customers' needs throughout North America.

The
integration of electric generation assets with origination and risk management of energy and energy-related commodities allows our merchant energy business to manage energy price
risk over geographic regions and over time. Our focus is on providing solutions to customers' energy needs, and our origination and risk management operation adds value to our generation assets by
providing national market access, market infrastructure, real-time market intelligence, risk management and arbitrage opportunities, and transmission and transportation expertise. Generation capacity
supports our origination and risk management operation by providing a source of reliable power supply that provides a physical hedge for some of our load-serving activities.

To
achieve our strategic objectives, we expect to continue to pursue opportunities that expand our access to customers and to support our origination and risk management operation with
generation assets that have diversified geographic, fuel, and dispatch characteristics. We also expect to use a disciplined growth strategy through originating transactions with large customers and by
acquiring and developing additional generating facilities when desirable to support our merchant energy business.

31

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Our
merchant energy business will focus on long-term, high-value sales of energy, capacity, and related products to large customers, including distribution utilities, industrial
customers, and large 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 the New England region, the New York region, the Mid-Atlantic region, Texas, Illinois, California, and certain areas in Canada.

The
growth of BGE and our other retail energy services businesses is expected through focused and disciplined expansion primarily from new customers.

Customer
choice, regulatory change, and energy market conditions significantly impact our business. In response, we regularly evaluate our strategies with these goals in mind: to improve
our competitive position, to anticipate and adapt to business environment and regulatory changes, and to maintain a strong balance sheet and 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. This included the implementation of workforce reduction programs, termination of all planned development projects not under construction, and the acceleration of our exit strategy
for certain non-core assets.

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



Business Environment

General Industry

The utility industry and energy markets continue to experience significant changes as a result of less liquid and more volatile wholesale markets, deteriorating credit
qualities of various industry participants, volatile power and fuel prices, excess generation in the domestic markets, and the slow recovery of the U.S. economy.

Due
to market conditions in 2001, we canceled our separation plans and terminated our power business services agreement with Goldman Sachs on October 26, 2001 and decided to maintain our
existing corporate structure. We also terminated all planned development projects not under construction. Separately, we initiated efforts to reduce costs in order to become more competitive and to
sell certain non-core assets to focus attention and capital resources on our core energy businesses.

During
2002, the energy markets were affected by 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 allegedly designed to manipulate market prices. In addition, several merchant
energy businesses significantly reduced their energy trading activities due to deteriorating credit quality.

Beginning
in the second quarter of 2002, several regional energy markets experienced a significant decline in liquidity. As a result of the reduced market liquidity, our origination and
risk management operation held energy positions in certain markets longer than it otherwise would have during the first half of 2002. In response to this reduced market liquidity, we reduced these
positions and continue to modify our positions to reflect the underlying liquidity of the various regional energy markets.

As
discussed above, certain companies in the energy industry have been experiencing deteriorating credit quality. We continue to actively manage our credit portfolio to attempt to reduce
the impact of a potential counterparty default. We discuss our counterparty credit risk in more detail in theMarket Risksection.

We
also continue to examine plans to achieve our strategies and to further strengthen our balance sheet and enhance our liquidity. We discuss our strategies in the Strategysection. We discuss our
liquidity in theFinancial Conditionsection.

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:



32

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Our
origination and risk management operation provides BGE with 100% of the energy and capacity required to meet its standard offer service obligations through June 30, 2003. Our
origination and risk management operation obtains the energy and capacity to supply BGE's standard offer service obligations from affiliates that own Calvert Cliffs and BGE's former fossil plants,
supplemented with energy and capacity purchased from the wholesale market, as necessary.

In
August 2001, BGE entered into contracts with our origination and risk management operation to supply 90% and Allegheny Energy Supply Company, LLC (Allegheny) to supply the remaining
10% of BGE's standard offer service for the final three years (July 1, 2003 to June 30, 2006) of the transition period. Currently, the credit ratings of Allegheny are below investment grade. Under the
terms of the contract, in certain circumstances, BGE has the right to request additional credit support from Allegheny to secure performance under the contract. If BGE was to exercise these rights and
Allegheny did not meet such request, BGE could liquidate and terminate the contract. As of the date of this report, Allegheny is in compliance with the terms of the contract.

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

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

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 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 theFERC RegulationRegional Transmission Organizations and
Standard Market Designsection.

As
a result of ongoing litigation before the FERC regarding sales into the spot markets of the California Independent System Operator and Power Exchange, we estimate that we may be
required to pay refunds of between $3 and $4 million for transactions that we entered into with these entities for the period between October 2000 and June 2001. However, our estimate is based on
current information and because litigation is ongoing, new events could occur that could cause the actual amount, if any, to be materially different from our estimate.

Gas Competition

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

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. Prior to July 1, 2000, BGE's
regulated electric rates consisted primarily of a "base rate" and a "fuel rate." BGE unbundled its electric rates to show separate components for delivery service, competitive transition charges,
standard offer services (generation), transmission, universal service, and taxes. The rates for BGE's regulated gas business continue to consist of a "base rate" and a "fuel rate."

33

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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.

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

As
a result of the 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.

Fuel Rate

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

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

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

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

FERC Regulation

Regional Transmission Organizations and Standard Market Design

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.

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 the FERC's RTO order, and will require RTOs to substantially comply with its provisions. The SMD proposal requires 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. However, in early 2003, the FERC announced that it would issue a report on SMD and again solicit comments from interested parties.

In
1997, BGE turned over the operation of its transmission facilities to PJM, a FERC approved RTO, which generally conducts its operations in accordance with FERC standard market design
principles. We believe that the SMD proposal may lead to long-term benefits for Constellation Energy and BGE because the proposal will promote competition in regions where it is implemented. However,
until the proposal is finalized, we cannot predict its effect on our, or BGE's, financial results.

Cash Management

In August 2002, the FERC issued proposed rules for the regulation of cash management practices of a regulated subsidiary of a nonregulated parent. As currently proposed, we do
not believe the proposed rule will have a material effect on our, and BGE's, financial results. We discuss our cash management arrangement inNote 15.

Weather

Merchant Energy Business

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

34

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BGE

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

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

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

During
the cooling season, hotter weather is measured by more cooling degree-days and results in greater demand for electricity to operate cooling systems. During the heating season,
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 2002 and 2001, 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.

|                                  |  | 2002  |   | 2001  |    | 30-year
Average
|--------------------------------- |  | ----- | - | ----- | -- | ---------------
|Cooling degree-days               |  | 1,006 |   | 787   |    | 836            
|Percentage change from prior year |  | 27.8  | % | 6.9   | %  |                
|Heating degree-days               |  | 4,542 |   | 4,514 |    | 4,736          
|Percentage change from prior year |  | 0.6   | % | (8.5  | )% |                

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 inNote 11andItem 1.
BusinessEnvironmental Matterssection. You will find details of our legal matters inNote 11. Some of the
information is about costs that may be material to our financial results.

Accounting Standards Adopted and Issued

We discuss recently adopted and issued accounting standards inNote 1.

35

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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. Changes in other income, fixed charges and income taxes are discussed in the aggregate for all segments in theConsolidated Nonoperating Income and
Expensessection.

Overview

Net Income

|                                                                      |                                                                                | 2002 |       | 2001  |   | 2000  |       
|--------------------------------------------------------------------- | ------------------------------------------------------------------------------ | ---- | ----- | ----- | - | ----- | ------
|
|
|Net Income Before Special Items Included in Operations:               |                                                                                |      |       |       |   |       |       
|Merchant energy                                                       |                                                                                | $    | 275.5 |       | $ | 291.2 |       
|Regulated electric                                                    |                                                                                |      | 119.8 |       |   | 84.5  |       
|Regulated gas                                                         |                                                                                |      | 31.9  |       |   | 38.3  |       
|Other nonregulated                                                    |                                                                                |      | (13.1 | )     |   | (26.8 | )     
|                                                                      |                                                                               
|Net Income Before Special Items Included in Operations                |                                                                                |      | 414.1 |       |   | 387.2 |       
|Special Items Included in Operations:                                 |                                                                                |      |       |       |   |       |       
|                                                                      | Net gain on sales of investments and other assets                              |      |       | 166.7 |   |       | 1.9   
|                                                                      | Workforce reduction costs                                                      |      |       | (38.0 | ) |       | (64.1 
|                                                                      | 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  | ) |       |      
|                                                                      | Impairments of real estate, senior-living, and international investments       |      |       | (1.2  | ) |       | (69.7 
|                                                                      | Contract termination related costs                                             |      |       |      |   |       | (139.6
|                                                                      | Reduction of financial investment                                              |      |       |      |   |       | (2.8  
|                                                                      | Deregulation transition cost                                                   |      |       |      |   |       |      
|                                                                      |                                                                               
|Net Income Before Cumulative Effect of Change in Accounting Principle |                                                                                |      | 525.6 |       |   | 82.4  |       
|Cumulative Effect of Change in Accounting Principle                   |                                                                                |      |      |       |   | 8.5   |       
|                                                                      |                                                                               
|Net Income                                                            |                                                                                | $    | 525.6 |       | $ | 90.9  |       
|                                                                      |                                                                               

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

2002

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



These
increases were partially offset by special items recorded in 2002 as previously discussed in theSignificant Eventssection 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 are impacted by the dilution resulting from the issuance of 13.2 million of common shares during 2001.

2001

Our
total net income for 2001 decreased $254.4 million, or $1.73 per share, compared to 2000 mostly because the special items included in operations as previously discussed in the Significant Eventssection
more than offset the $69.9 million, or $.29 per share, increase in our net income before special items.

Net
income before special items was $387.2 million, or $2.41 per share, in 2001 compared to $317.3 million, or $2.12 per share, in 2000. Net income before special items was higher
compared to 2000 mostly because BGE recorded $75.0 million pre-tax, or approximately $.30 per share, of amortization expense for the reduction of our generating plants associated with the deregulation
of electric generation in 2000 that had a negative impact in that year. In addition, we had higher earnings from our regulated gas business in 2001 mostly because of increases in

36

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the sharing mechanism under our gas cost adjustment clauses and the increase in our base rates. These increases were offset by
the impact of a 6.5% annual electric residential rate reduction that was effective July 1, 2000.

The
decrease in total net income for 2001 compared to 2000 also was partially offset by the following:



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

Merchant Energy Business

Background

Our merchant energy business is a competitive provider of energy solutions for large customers in North America. As discussed in theBusiness
EnvironmentElectric Competitionsection, in connection with the July 1, 2000 implementation of customer choice in Maryland, BGE's generating assets became part of
our nonregulated merchant energy business, and our origination and risk management operation began selling to BGE the energy and capacity required to meet its standard offer service obligations for
the first three years (July 1, 2000 to June 30, 2003) of the transition period.

In
August 2001, BGE entered into a contract with our origination and risk management operation to provide 90% of the energy and capacity required for BGE to meet its standard offer
service requirements for the final three years (July 1, 2003 to June 30, 2006) of the transition period. Also effective July 1, 2000, merchant energy business revenues include 90% of the competitive
transition charges (CTC revenues) BGE collects from its customers and the portion of BGE's revenues providing for nuclear decommissioning costs.

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 theCritical Accounting Policiessection and inNote 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 theCompetitive SupplyMark-to-Market Revenuessection. We discuss
mark-to-market accounting and the accounting policies for the merchant energy business further in theCritical Accounting Policiessection and in Note 1.

As
a result of the changes in our organization and senior management in late 2001, including the cancellation of our business separation and the termination of the power business
services agreement with Goldman Sachs, we re-evaluated our load-serving activities in Texas and New England as discussed in more detail in theCompetitive
Supplysection. We determined that since we manage these activities as a physical delivery business rather than a trading business, it is appropriate to apply accrual
accounting for these activities. After the re-designation of existing contracts to non-trading, we began to record revenues and expenses on a gross basis, but this did not have a material impact on
earnings because the resulting increase in revenues was accompanied by a similar increase in fuel and purchased energy expenses.

As
a result of applying accrual accounting to an increasing portion of our merchant energy business, including the January 1, 2003 implementation of EITF 02-3, future mark-to-market
earnings will be lower than they otherwise would have been
because we will record the margin on new transactions as power is delivered to customers over the contract term using accrual accounting rather than in full at the inception of each new contract.
However, we expect accrual earnings for 2003 to be $52 million higher than they would have been prior to applying EITF 02-3, reflecting the 2003 portion of the fair value of contracts converted to
accrual accounting using market prices as of December 31, 2002.

While
we cannot predict the ongoing impact of applying EITF 02-3, the timing of recognizing earnings on new transactions will change. In general, earnings on new transactions will no
longer be recognized at the inception of the transactions under mark-to-market accounting because they will be recognized over the term of the transaction. However, we cannot predict the total impact
of these changes on our earnings for the reasons discussed in theCritical Accounting Policiessection.

Additionally,
we also expect lower earnings volatility for this portion of our business because unrealized changes in the fair value of load-serving contracts will no longer be recorded
as revenue at the time of the change under mark-to-market accounting as is required for trading activities. Any contracts subject to EITF 02-3 must be accounted for on the accrual basis and recorded
gross rather than net upon application of EITF 02-3, which was effective after October 25, 2002 for new non-derivative transactions (including spot market purchases and sales) and
January 1, 2003 for contracts existing as of October 25, 2002.

37

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Our
merchant energy business results were as follows:

Net Income

|                                                       |                                                                                | 2002 |         | 2001  |   | 2000    |       
|------------------------------------------------------ | ------------------------------------------------------------------------------ | ---- | ------- | ----- | - | ------- | ------
|
|
|Revenues                                               |                                                                                | $    | 2,765.7 |       | $ | 1,765.5 |       
|Fuel and purchased energy expenses                     |                                                                                |      | 1,151.3 |       |   | 484.5   |       
|Operations and maintenance expenses                    |                                                                                |      | 787.4   |       |   | 597.8   |       
|Workforce reduction costs                              |                                                                                |      | 26.5    |       |   | 46.0    |       
|Impairment losses and other costs                      |                                                                                |      | 14.4    |       |   | 46.9    |       
|Contract termination related costs                     |                                                                                |      |        |       |   | 224.8   |       
|Depreciation and amortization                          |                                                                                |      | 242.8   |       |   | 174.9   |       
|Taxes other than income taxes                          |                                                                                |      | 83.5    |       |   | 49.4    |       
|Net loss on sales of assets                            |                                                                                |      | 3.7     |       |   |        |       
|                                                       |                                                                               
|Income from Operations                                 |                                                                                | $    | 456.1   |       | $ | 141.2   |       
|                                                       |                                                                               
|Net Income                                             |                                                                                | $    | 247.2   |       | $ | 93.1    |       
|                                                       |                                                                               
|Net Income Before Special Items Included in Operations |                                                                                | $    | 275.5   |       | $ | 291.2   |       
|                                                       | Workforce reduction costs                                                      |      |         | (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
|                                                       | Deregulation transition cost                                                   |      |         |      |   |         |      
|                                                       |                                                                               
|Net Income                                             |                                                                                | $    | 247.2   |       | $ | 93.1    |       
|                                                       |                                                                               

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 origination and risk management operation manages our costs of procuring fuel and energy and revenues we realize from the sale of energy to our customers. 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. We discuss non-fuel direct costs, such as ancillary
services, transmission costs, financing, and legal costs in conjunction with other operations and maintenance expenses later in this section.

We
analyze our merchant energy revenues and fuel and purchased energy expenses in the following categories because of differences in the revenue sources, the nature of fuel and purchased
energy expenses, and the risk profile of each category.



38

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

|                                    |                                       | 2002 |   |         |  | 2001 |   |   |         | 2000 |     |   |  
|----------------------------------- | ------------------------------------- | ---- | - | ------- |  | ---- | - | - | ------- | ---- | --- | - | -
|
|
|Revenues:                           |                                       |      |   |         |  |      |   |   |         |      |     |   |  
|                                    | PJM Platform                          |      | $ | 1,391.4 |  |      |   | $ | 1,379.2 |      |     |   | $
|                                    | Plants with Power Purchase Agreements |      |   | 456.4   |  |      |   |   | 70.8    |      |     |   |  
|                                    | Competitive Supply                    |      |   | 825.7   |  |      |   |   | 175.8   |      |     |   |  
|                                    | Other                                 |      |   | 92.2    |  |      |   |   | 139.7   |      |     |   |  
|                                    |                                      
|                                    | Total                                 |      | $ | 2,765.7 |  |      |   | $ | 1,765.5 |      |     |   | $
|                                    |                                      
|Fuel and purchased energy expenses: |                                       |      |   |         |  |      |   |   |         |      |     |   |  
|                                    | PJM Platform                          |      | $ | 527.5   |  |      |   | $ | 420.9   |      |     |   | $
|                                    | Plants with Power Purchase Agreements |      |   | 40.0    |  |      |   |   | 13.9    |      |     |   |  
|                                    | Competitive Supply                    |      |   | 552.9   |  |      |   |   |        |      |     |   |  
|                                    | Other                                 |      |   | 30.9    |  |      |   |   | 49.7    |      |     |   |  
|                                    |                                      
|                                    | Total                                 |      | $ | 1,151.3 |  |      |   | $ | 484.5   |      |     |   | $
|                                    |                                      
|
|                                    | PJM Platform                          |      | $ | 863.9   |  | 53   | % | $ | 958.3   |      | 75  | % | $
|                                    | Plants with Power Purchase Agreements |      |   | 416.4   |  | 26   |   |   | 56.9    |      | 4   |   |  
|                                    | Competitive Supply                    |      |   | 272.8   |  | 17   |   |   | 175.8   |      | 14  |   |  
|                                    | Other                                 |      |   | 61.3    |  | 4    |   |   | 90.0    |      | 7   |   |  
|                                    |                                      
|                                    | Total                                 |      | $ | 1,614.4 |  | 100  | % | $ | 1,281.0 |      | 100 | % | $
|                                    |                                      

PJM Platform

|                                        |  | 2002 |         | 2001 |   | 2000   
|--------------------------------------- |  | ---- | ------- | ---- | - | -------
|
|
|Revenues                                |  | $    | 1,391.4 |      | $ | 1,379.2
|Fuel and purchased energy expenses      |  |      | 527.5   |      |   | 420.9  
|                                       
|Revenues less fuel and purchased energy |  | $    | 863.9   |      | $ | 958.3  
|                                       

Revenues

BGE Standard Offer Service

The
majority of PJM Platform revenues arise from BGE standard offer service. Revenues from BGE's standard offer service requirements decreased $8.3 million, including CTC and decommissioning revenues
that decreased $4.3 million, in 2002 compared to 2001.

These
decreases were due to approximately 1,200 megawatts of large commercial and industrial customers leaving BGE's standard offer service in the second quarter of 2002 and electing
other electric generation suppliers, partially offset by higher volumes sold to BGE due to warmer summer weather. However, approximately one-third of the load for large commercial and industrial
customers left BGE's standard offer service and 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. Revenues from BGE Home were $45.3 million in 2002. BGE Home is included in our other nonregulated businesses.

CTC
revenues are impacted by the CTC rates our merchant energy business receives from BGE customers as well as the volumes delivered to BGE customers. The CTC rates decline over the
transition period as previously discussed in theElectric CompetitionMarylandsection.

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

Other PJM Revenues

Other
merchant energy revenues in the PJM region decreased $32.6 million in 2002 compared to 2001 mostly because of the following:



Other
merchant energy revenues in the PJM region increased $69.5 million in 2001 compared to 2000 mostly because of the following:



Fuel and Purchased Energy Expenses

Our merchant energy business had higher fuel and purchased energy expenses in the PJM region 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.

39

---

Our
merchant energy business began an extended outage at Unit 1 of Calvert Cliffs during the first quarter of 2002 to replace the unit's steam generators, which was completed at the end
of June 2002. As a result, our merchant energy business had lower revenues and higher operating costs, including higher purchased energy to meet BGE's standard offer service. Calvert Cliffs will
replace the steam generators for Unit 2 during the 2003 refueling outage. Based on our current outage schedule, we expect the 2003 outage to be shorter than the 2002 extended outage. However, this
outage will be significantly longer than a normal refueling outage. We expect lower annual revenues and higher annual operating costs in 2003 from Calvert Cliffs compared to 2001 due to the longer
outage.

Our
merchant energy business had higher fuel and purchased energy expenses in the PJM region in 2001 compared to 2000 mostly because 2001 reflects a full year's operation of the
generation plants that were transferred from BGE effective July 1, 2000. The fuel cost increase also reflects higher fuel prices for generating electricity mostly because coal prices increased during
2001 compared to 2000.

Plants with Power Purchase Agreements

|                                        |  | 2002 |       | 2001 |   | 2000
|--------------------------------------- |  | ---- | ----- | ---- | - | ----
|
|
|Revenues                                |  | $    | 456.4 |      | $ | 70.8
|Fuel and purchased energy expenses      |  |      | 40.0  |      |   | 13.9
|                                       
|Revenues less fuel and purchased energy |  | $    | 416.4 |      | $ | 56.9
|                                       

The increases in revenues and expenses primarily were 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

|                                        |  | 2002 |       | 2001 |   | 2000 
|--------------------------------------- |  | ---- | ----- | ---- | - | -----
|
|
|Accrual revenues                        |  | $    | 587.6 |      | $ |     
|Mark-to-market revenues                 |  |      | 238.1 |      |   | 175.8
|Fuel and purchased energy expenses      |  |      | 552.9 |      |   |     
|                                       
|Revenues less fuel and purchased energy |  | $    | 272.8 |      | $ | 175.8
|                                       

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

Accrual Revenues and Fuel and Purchased Energy Expenses

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. Texas and New England revenues were $310.5 million, and purchased energy expenses were $317.1 million. NewEnergy's revenues were $261.3
million, and purchased energy expenses were $211.6 million. 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 required us to remove the unamortized balance of these assets and liabilities, excluding the costs of any acquired contracts, from our Consolidated Balance Sheets by January 1,
2003.

After
the change in designation, the results of our Texas load-serving business 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 this business will be 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 will delay the recognition of earnings from this business in the future compared to what we would have recognized under
mark-to-market accounting. The change in designation of our Texas load-serving business did not impact our cash flows.

In
addition, our New England load-serving business 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 this business 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 and associated power purchase agreements entered into since the second quarter of
2002.

40

---

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.

We
discuss the implications of EITF 02-3 in more detail in theCritical Accounting Policiessection and inNote
1.

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 theCritical Accounting Policiessection and inNote
1. We also discuss the implications of EITF 02-3 on the mark-to-market method of accounting in theCritical Accounting Policiessection and inNote 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 theMarket Risksection. The
primary factors that cause fluctuations in our mark-to-market revenues and earnings are:



Mark-to-market
revenues were as follows:

|                              |                          | 2002                                              |       | 2001  |       | 2000  |      
|----------------------------- | ------------------------ | ------------------------------------------------- | ----- | ----- | ----- | ----- | -----
|
|
|Unrealized revenues           |                          |                                                   |       |       |       |       |      
|                              | Origination transactions |                                                   | $     | 160.4 |       | $     | 227.0
|                              | Risk management          |                                                   |       |       |       |       |      
|                              |                          | Unrealized changes in fair value                  |       |       | 66.9  |       |      
|                              |                          | Changes in valuation techniques                   |       |       | 10.8  |       |      
|                              |                          | Reclassification of settled contracts to realized |       |       | (45.4 | )     |      
|                              |                         
|                              | Total risk management    |                                                   |       | 32.3  |       |       | (70.9
|                              |                         
|Total unrealized revenues     |                          |                                                   | 192.7 |       |       | 156.1 |      
|Realized revenues             |                          |                                                   | 45.4  |       |       | 19.7  |      
|                              |                         
|Total mark-to-market revenues |                          | $                                                 | 238.1 |       | $     | 175.8 |      
|                              |                         

Revenues from origination transactions represent the initial unrealized fair value of new wholesale energy transactions (including restructurings)
at the time of contract execution to the extent permitted by applicable accounting rules. 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, we re-
designated our Texas load-serving business 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. Under EITF 02-3, we no longer record existing non-derivative contracts at fair value beginning January 1, 2003. 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 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 guidance on recording gains at the time of contract
origination as previously described, and fewer individually significant transactions in 2002 as compared to 2001.

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

41

---

Mark-to-Market Energy Assets and Liabilities

Our mark-to-market energy assets and liabilities are comprised of a combination of derivative and non-derivative (physical) contracts. The non-derivative assets and liabilities
primarily relate to load-serving activities originated prior to the shift to accrual accounting earlier this year. While some of these contracts represent commodities or instruments for which prices
are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future
market prices, contract quantities, or both. We discuss our modeling techniques later in this section.

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

|At December 31,                 |  | 2002 |         | 2001
|------------------------------- |  | ---- | ------- | ----
|
|
|Current Assets                  |  | $    | 144.0   |     
|Noncurrent Assets               |  |      | 1,348.2 |     
|                               
|Total Assets                    |  |      | 1,492.2 |     
|                               
|Current Liabilities             |  |      | 94.1    |     
|Noncurrent Liabilities          |  |      | 881.5   |     
|                               
|Total Liabilities               |  |      | 975.6   |     
|                               
|Net mark-to-market energy asset |  | $    | 516.6   |     
|                               

At December 31, 2002, the primary components of our net mark-to-market energy asset were as follows:

|                                                                                                                             |  | (In millions) |      
|---------------------------------------------------------------------------------------------------------------------------- |  | ------------- | -----
|Non-derivative contracts reversed as part of cumulative effect of a change in accounting principle effective January 1, 2003 |  | $             | 374.9
|Derivatives designated as hedges effective January 1, 2003                                                                   |  |               | (6.1 
|Derivatives designated as normal purchases and sales effective January 1, 2003                                               |  |               | 64.3 
|Other positions                                                                                                              |  |               | 83.5 
|                                                                                                                             | 
|Total                                                                                                                        |  | $             | 516.6
|                                                                                                                             | 

The non-derivative portion of the net asset represents the fair value of contracts that we reclassified to accrual effective January 1, 2003 as
required by EITF 02-3. Derivatives designated as hedges effective January 1, 2003 represent derivative contracts used to hedge our physical delivery contracts in connection with the implementation of
EITF 02-3. Derivatives designated as normal purchases and sales effective January 1, 2003, represent derivative contracts used to economically hedge our physical delivery contracts in connection with
the implementation of EITF 02-3 but which receive accrual accounting treatment. The remainder of the net asset primarily consists of a PJM generation hedge comprised of a group of options that serve
as an economic hedge of the PJM generation portfolio. These options give us the right to sell power at a floor price which is valuable to our generation operation when market prices are low and also
give us the right to buy power at a capped price, which adds value when the market prices are high. We have not designated these options as hedges under SFAS No. 133 due to the complexity of
qualifying options as effective hedges under the requirements of that standard.

The
following are the primary sources of the change in net mark-to-market energy asset during 2002 and 2001:

|                                                        |                                                   | 2002 |   | 2001  |  
|------------------------------------------------------- | ------------------------------------------------- | ---- | - | ----- | -
|
|
|Fair value beginning of year                            |                                                   |      |   |       | $
|Changes in fair value recorded as revenues              |                                                   |      |   |       |  
|                                                        | Origination transactions                          |      | $ | 160.4 |  
|                                                        | Unrealized changes in fair value                  |      |   | 66.9  |  
|                                                        | Changes in valuation techniques                   |      |   | 10.8  |  
|                                                        | Reclassification of settled contracts to realized |      |   | (45.4 | )
|                                                        |                                                   |      |   |       |  
|Total changes in fair value recorded as revenues        |                                                   |      |   |       |  
|Changes in fair value recorded as operating expenses    |                                                   |      |   |       |  
|Changes in value of exchange-listed futures and options |                                                   |      |   |       |  
|Net change in premiums on options                       |                                                   |      |   |       |  
|Texas contracts re-designated as non-trading            |                                                   |      |   |       |  
|Other changes in fair value                             |                                                   |      |   |       |  
|                                                        |                                                  
|Fair value at end of year                               |                                                   |      |   |       | $
|                                                        |                                                  

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:



42

---



We
discuss our Texas contracts re-designated as non-trading in more detail in theCompetitive Supplysection.

The
settlement terms of the net mark-to-market energy asset and sources of fair value as of December 31, 2002 are as follows:

|                                        |  | Settlement Term |      |   |  
|--------------------------------------- |  | --------------- | ---- | - | -
|
|
|
|
|Prices provided by external sources (1) |  | $               | 50.1 |   | $
|Prices based on models                  |  |                 | (0.2 | ) |  
|                                        | 
|Total net mark-to-market energy asset   |  | $               | 49.9 |   | $
|                                        | 

The implementation of EITF 02-3 significantly impacted the amount and composition of the net mark-to-market energy asset. The table below presents the settlement terms of our net mark-to-market energy
asset as of January 1, 2003 after reflecting the impact of implementing EITF 02-3. We discuss EITF 02-3 and the effect of its implementation in more detail in theCritical
Accounting Policiessection and inNote 1.

|                                        |  | Settlement Term After Reflecting Implementation of EITF 02-3 |      |  |  
|--------------------------------------- |  | ------------------------------------------------------------ | ---- |  | -
|
|
|
|Prices provided by external sources (1) |  | $                                                            | 9.7  |  | $
|Prices based on models                  |  |                                                              | 0.8  |  |  
|                                        | 
|Total net mark-to-market energy asset   |  | $                                                            | 10.5 |  | $
|                                        | 

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 tables 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:



43

---



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:



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 origination 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 tables 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 tables 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 tables. However, based upon the nature of the origination 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 tables represent expected future cash flows based on the level of forward prices and volatility factors as of December 31, 2002 and could change significantly as a
result of future changes in these factors. Additionally, because the depth and liquidity of the power markets varies substantially between regions and time periods, the prices used to determine fair
value could be affected significantly by the volume of transactions executed.

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

|                                        |  | 2002 |      | 2001 |   | 2000 
|--------------------------------------- |  | ---- | ---- | ---- | - | -----
|
|
|Revenues                                |  | $    | 92.2 |      | $ | 139.7
|Fuel and purchased energy expenses      |  |      | 30.9 |      |   | 49.7 
|                                       
|Revenues less fuel and purchased energy |  | $    | 61.3 |      | $ | 90.0 
|                                       

We analyze the revenues and fuel and purchased energy expenses of the final category of our merchant energy business below.

Revenues

Our other merchant energy business revenues decreased in 2002 compared to 2001 mostly because we had lower revenues of $23.4 million from our mid-continent region facilities
that commenced operations in mid-summer of 2001 primarily due to lower output from these facilities because of a less favorable relationship between energy prices and gas costs. In addition, we had
lower revenues of $14.0 million from our investments in qualifying facilities and domestic power projects. We discuss our investments in qualifying facilities and domestic power projects in more
detail on the next page.

Our
other merchant energy business revenues decreased in 2001 compared to 2000 mostly because of the following:



44

---



These
lower revenues were partially offset by higher revenues of $59.2 million from our mid-continent region gas-fired peaking facilities that commenced operations in mid-summer of 2001.

Investments in Qualifying Facilities and Domestic Power Projects

Our
merchant energy business holds up to a 50% ownership interest in 28 operating domestic energy projects that consist of electric generation, fuel processing, or fuel handling facilities. Of these
28 projects, 20 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. Earnings from our investments were $9.1 million in 2002, $23.1 million in 2001, and $50.2 million in 2000.

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 as discussed below. The
decrease in revenues in 2001 compared to 2000 was primarily due to lower revenues from our California projects.

California Power Purchase Agreements

Our
merchant energy business has $260.6 million invested in partnerships that own 13 operating power projects of which our ownership percentage represents 137 megawatts of electricity that are sold to
Pacific Gas & Electric (PGE) and to Southern California Edison (SCE) in California under power purchase agreements. Our merchant energy business was not paid in full for its sales from these plants to
the two utilities from November 2000 through early April 2001. At December 31, 2001, our portion of the amount due for unpaid power sales from these utilities was approximately $45 million. We
recorded reserves of approximately 20% of this amount in 2001.

Through
the date of this report, we received the $45 million for unpaid power sales plus interest. We reversed all of our credit reserves that totaled $9.1 million during the first
quarter of 2002 as payments ensued following court-approved restructuring agreements.

Revenues
from these projects, net of credit reserves, were $20.0 million in 2002, $22.1 million in 2001, and $44.1 million in 2000. While California power prices were significantly lower
during 2002 compared to 2001, 2001 results were reduced by credit reserves established for our exposure in California. These reserves were subsequently reversed in 2002 as discussed above, which had a
positive impact in 2002.

Revenues
decreased in 2001 compared to 2000 because of lower power prices in California during the second half of 2001. While energy rates were higher during the first half of 2001, the
higher rates were offset by reserves established for our exposure in California during that year.

The
projects entered into agreements with PGE through July 2006 and SCE through April 2007 that provide for fixed-price payments averaging $53.70 per megawatt-hour plus the stated
capacity payments in the original agreements.

Fuel and Purchased Energy Expenses

Our other merchant energy business fuel and purchased energy expenses decreased in 2002 compared to 2001 mostly because we had lower fuel and purchased energy for our
mid-continent region facilities primarily due to lower demand for the output of these facilities.

Operations and Maintenance Expenses

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:



Our
merchant energy business operations and maintenance expenses increased $210.5 million in 2001 compared to 2000 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 the following in 2002:



45

---







Our merchant energy business recognized the following in 2001:



We
discuss these special items in more detail in theSignificant Eventssection and inNote
2.

As
a result of our workforce reduction programs and other process improvement initiatives, our merchant energy business expects to realize cost savings of approximately $44 million
partially offset by other increases in operating costs in 2003.

Depreciation and Amortization Expense

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.

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

Taxes Other Than Income Taxes

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.

Merchant
energy taxes other than income taxes increased $24.8 million in 2001 compared to 2000 mostly because of taxes other than income taxes associated with the generation plants that
were transferred from BGE effective July 1, 2000. Additionally, 2001 expenses include taxes other than income taxes associated with Nine Mile Point and the new generating facilities.

Regulated Electric Business

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

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

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.

Net Income

|                                                       |  | 2002 |         | 2001 |   | 2000    |  
|------------------------------------------------------ |  | ---- | ------- | ---- | - | ------- | -
|
|
|Revenues                                               |  | $    | 1,966.0 |      | $ | 2,040.0 |  
|Fuel and purchased energy expenses                     |  |      | 1,080.7 |      |   | 1,192.8 |  
|Operations and maintenance expenses                    |  |      | 252.4   |      |   | 258.7   |  
|Workforce reduction costs                              |  |      | 34.0    |      |   | 55.7    |  
|Depreciation and amortization                          |  |      | 174.2   |      |   | 173.3   |  
|Taxes other than income taxes                          |  |      | 137.0   |      |   | 139.5   |  
|                                                       | 
|Income from Operations                                 |  | $    | 287.7   |      | $ | 220.0   |  
|                                                       | 
|Net Income                                             |  | $    | 99.3    |      | $ | 50.9    |  
|                                                       | 
|Net Income Before Special Items Included in Operations |  | $    | 119.8   |      | $ | 84.5    |  
|Workforce reduction costs                              |  |      | (20.5   | )    |   | (33.6   | )
|                                                       | 
|Net Income                                             |  | $    | 99.3    |      | $ | 50.9    |  
|                                                       | 

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.

46

---

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



Net
income from the regulated electric business decreased in 2001 compared to 2000 mostly because of the July 1, 2000 deregulation of electric generation as discussed later in this
section.

Electric Revenues

The changes in electric revenues in 2002 and 2001 compared to the respective prior year were caused by:

|                                                             |  | 2002 |       | 2001 |  
|------------------------------------------------------------ |  | ---- | ----- | ---- | -
|
|
|Distribution sales volumes                                   |  | $    | 32.7  |      | $
|Standard offer service                                       |  |      | (70.2 | )    |  
|Fuel rate surcharge                                          |  |      | (43.2 | )    |  
|                                                             | 
|Total change in electric revenues from electric system sales |  |      | (80.7 | )    |  
|Interchange and other sales                                  |  |      |      |      |  
|Other                                                        |  |      | 6.7   |      |  
|                                                             | 
|Total change in electric revenues                            |  | $    | (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 2002 and 2001 compared to the respective prior year were:

|            |  | 2002 |   | 2001 |  
|----------- |  | ---- | - | ---- | -
|
|Residential |  | 8.0  | % | 0.3  | %
|Commercial  |  | 3.2  |   | 0.7  |  
|Industrial  |  | 0.7  |   | (0.7 | )

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.

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

Standard Offer Service

BGE provides standard offer service for customers that do not select an alternative generation supplier as previously discussed. Standard offer service revenues decreased in
2002 compared to 2001 primarily as a result of large
commercial and industrial customers leaving BGE's standard offer service and electing other electric generation suppliers. These decreased revenues were partially offset by increased sales to
residential customers 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 service, BGE also had lower purchased energy expense as discussed in theElectric Fuel and
Purchased Energy Expensessection.

Standard
offer service revenues decreased in 2001 compared to 2000 mostly due to:



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

Fuel Rate Surcharge

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

Interchange and Other Sales

"Interchange and other sales" are sales in the PJM energy market and to others. PJM is a FERC approved RTO that also operates a regional power pool with members that include
many wholesale market participants, as well as BGE and other utility companies. Prior to the implementation of customer choice, BGE sold energy to

47

---

PJM members and to others after it had satisfied the demand for electricity in its own system.

Effective
July 1, 2000, BGE no longer engages in interchange sales, as these activities are included in our merchant energy business, which resulted in a decrease in interchange and
other sales for 2001 compared to 2000.

Electric Fuel and Purchased Energy Expenses

|                                                           |  | 2002 |         | 2001 |   | 2000   
|---------------------------------------------------------- |  | ---- | ------- | ---- | - | -------
|
|
|Actual costs                                               |  | $    | 1,080.7 |      | $ | 1,150.5
|Recovery of costs deferred under electric fuel rate clause |  |      |        |      |   | 42.3   
|                                                          
|Total electric fuel and purchased energy expenses          |  | $    | 1,080.7 |      | $ | 1,192.8
|                                                          

Actual Costs

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

Our
actual costs of fuel and purchased energy decreased in 2002 compared to 2001 mostly because BGE purchased less energy due to large commercial and industrial customers leaving BGE's
fixed price standard offer service and electing other electric generation suppliers.

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

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

Electric Operations and Maintenance Expenses

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.

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

Workforce Reduction Costs

BGE's electric business recognized expenses associated with our workforce reduction efforts as previously discussed in theSignificant
Eventssection and inNote 2.

As
a result of our workforce reduction programs and other process improvement initiatives, our electric business expects to realize cost savings of approximately $17 million partially
offset by other increases in operating costs in 2003.

Electric Depreciation and Amortization Expense

Regulated electric depreciation and amortization expense was about the same during 2002 compared to 2001. Regulated electric depreciation and amortization expense decreased
$146.6 million during 2001 compared to 2000 mostly due to:



Electric Taxes Other Than Income Taxes

Regulated electric taxes other than income taxes were about the same during 2002 compared to 2001. Regulated electric taxes other than income taxes decreased $18.3 million
during 2001 compared to 2000 mostly due to the absence of taxes other than income taxes associated with the generation assets that were transferred to the merchant energy business effective July 1,
2000 partially offset by fewer tax credits.

48

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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.

Net Income

|                                                       |                           | 2002 |       | 2001 |   | 2000 
|------------------------------------------------------ | ------------------------- | ---- | ----- | ---- | - | -----
|
|
|Revenues                                               |                           | $    | 581.3 |      | $ | 680.7
|Gas purchased for resale expenses                      |                           |      | 316.7 |      |   | 401.3
|Operations and maintenance expenses                    |                           |      | 102.9 |      |   | 104.3
|Workforce reduction costs                              |                           |      | 1.3   |      |   | 1.3  
|Depreciation and amortization                          |                           |      | 47.4  |      |   | 47.7 
|Taxes other than income taxes                          |                           |      | 34.4  |      |   | 34.3 
|                                                      
|Income from Operations                                 |                           | $    | 78.6  |      | $ | 91.8 
|                                                      
|Net Income                                             |                           | $    | 31.1  |      | $ | 37.5 
|                                                      
|Net Income Before Special Items Included in Operations |                           | $    | 31.9  |      | $ | 38.3 
|                                                       | Workforce reduction costs |      |       | (0.8 | ) |      
|                                                      
|Net Income                                             |                           | $    | 31.1  |      | $ | 37.5 
|                                                      

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 decreased during 2002 compared to 2001 mostly due to a $7.7 million pre-tax disallowed portion of a previously established regulatory asset as
discussed in theGas Cost Adjustmentssection and a $3.7 million pre-tax decrease in the shareholders' portion of the sharing mechanism under our gas
cost adjustment clauses.

Net
income from our regulated gas business increased during 2001 compared to 2000 mostly due to a $3.6 million pre-tax increase in the shareholders' portion of the sharing mechanism
under our gas cost adjustment clauses and an increase in our base rates.

Gas Revenues

The changes in gas revenues in 2002 and 2001 compared to the respective prior year were caused by:

|                                                   |  | 2002 |       | 2001 |  
|-------------------------------------------------- |  | ---- | ----- | ---- | -
|
|
|Distribution sales volumes                         |  | $    | 1.4   |      | $
|Base rates                                         |  |      | (2.9  | )    |  
|Weather normalization                              |  |      | (0.5  | )    |  
|Gas cost adjustments                               |  |      | (55.8 | )    |  
|                                                   | 
|Total change in gas revenues from gas system sales |  |      | (57.8 | )    |  
|Off-system sales                                   |  |      | (38.8 | )    |  
|Other                                              |  |      | (2.8  | )    |  
|                                                   | 
|Total change in gas revenues                       |  | $    | (99.4 | )    | $
|                                                   | 

Distribution Sales Volumes

The percentage changes in our distribution sales volumes, by type of customer, in 2002 and 2001 compared to the respective prior year were:

|            |  | 2002 |   | 2001  |   
|----------- |  | ---- | - | ----- | --
|
|Residential |  | 3.5  | % | (7.8  | )%
|Commercial  |  | 7.1  |   | 3.5   |   
|Industrial  |  | (1.4 | ) | (25.2 | ) 

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.

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

Base Rates

Base rate revenues decreased during 2002 compared to 2001 mostly because of a decrease in the rate approved by the Maryland PSC associated with the energy conservation
surcharge program.

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

49

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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 inNote
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 decreased $3.7 million during 2002 compared to 2001. The shareholders' portion
increased $3.6 million during 2001 compared to 2000.

Effective
November 2001, the Maryland PSC approved an order that modifies certain provisions of the market-based rates incentive mechanism. These provisions require that BGE secure
fixed-price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for the November through March period. These fixed price contracts are not subject to sharing
under the market-based rates incentive mechanism. We do not expect these changes to have a material impact on our financial results.

Delivery
service customers 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 volumes.

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

In
December 2002, a Hearing Examiner from the Maryland PSC issued a proposed order related to our annual gas adjustment clause review proceeding that will allow us to recover $1.7
million of a previously established regulatory asset of $9.4 million for certain credits that were over-refunded to customers through our market-based rates. BGE reserved the remaining difference of
$7.7 million as disallowed fuel costs.

However,
we appealed the proposed order. As of the date of this report, the Maryland PSC has not acted on BGE's appeal.

Off-System Sales

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

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

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

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 decreased during 2002 as 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 Adjustmentssection.

Gas
costs increased during 2001 compared to 2000 mostly because gas we purchased was at a higher price partially offset by less gas purchased for both system and off-system sales.

Gas Operations and Maintenance Expenses

Regulated gas operations and maintenance expenses were about the same during 2002 and 2001 compared to the respective prior year. 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 previously discussed in theSignificant
Eventssection and inNote 2.

As
a result of our workforce reduction programs and other process improvement initiatives, our gas business expects to realize cost savings of approximately $4 million partially offset
by other increases in operating costs in 2003.

50

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Other Nonregulated Businesses

Net Income

|                                                                             |                                                                         | 2002 |       | 2001  |   | 2000  |      
|---------------------------------------------------------------------------- | ----------------------------------------------------------------------- | ---- | ----- | ----- | - | ----- | -----
|
|
|Revenues                                                                     |                                                                         | $    | 537.4 |       | $ | 552.6 |      
|Operating expenses                                                           |                                                                         |      | 505.9 |       |   | 510.7 |      
|Workforce reduction costs                                                    |                                                                         |      | 1.0   |       |   | 2.7   |      
|Impairment losses and other costs                                            |                                                                         |      | 10.8  |       |   | 111.9 |      
|Depreciation and amortization                                                |                                                                         |      | 16.6  |       |   | 23.2  |      
|Taxes other than income taxes                                                |                                                                         |      | 4.3   |       |   | 3.4   |      
|Net gain on sales of investments and other assets                            |                                                                         |      | 265.0 |       |   | 6.2   |      
|                                                                             |                                                                        
|Income (Loss) from Operations                                                |                                                                         | $    | 263.8 |       | $ | (93.1 | )    
|                                                                             |                                                                        
|Net Income (Loss) Before Cumulative Effect of Change in Accounting Principle |                                                                         | $    | 148.0 |       | $ | (99.1 | )    
|Cumulative Effect of Change in Accounting Principle                          |                                                                         |      |      |       |   | 8.5   |      
|                                                                             |                                                                        
|Net Income (Loss)                                                            |                                                                         | $    | 148.0 |       | $ | (90.6 | )    
|                                                                             |                                                                        
|Net Loss Before Special Items Included in Operations                         |                                                                         | $    | (13.1 | )     | $ | (26.8 | )    
|                                                                             | Net gain on sales of investments and other assets                       |      |       | 169.1 |   |       | 1.9  
|                                                                             | Workforce reduction costs                                               |      |       | (0.7  | ) |       | (1.7 
|                                                                             | Costs associated with exit of BGE Home merchandise stores               |      |       | (6.1  | ) |       |     
|                                                                             | Impairment of real estate, senior-living, and international investments |      |       | (1.2  | ) |       | (69.7
|                                                                             | Reduction of financial investment                                       |      |       |      |   |       | (2.8 
|                                                                             |                                                                        
|Net Income (Loss) Before Cumulative Effect of Change in Accounting Principle |                                                                         |      | 148.0 |       |   | (99.1 | )    
|Cumulative Effect of Change in Accounting Principle                          |                                                                         |      |      |       |   | 8.5   |      
|                                                                             |                                                                        
|Net Income (Loss)                                                            |                                                                         | $    | 148.0 |       | $ | (90.6 | )    
|                                                                             |                                                                        

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 our other nonregulated businesses increased during 2002 compared to 2001 mostly because of the following:



These
increases were partially offset by the following:



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



We
discuss our special items further in theSignificant Eventssection and inNote 2.

In
addition, we recognized an $8.5 million after-tax, or $.05 per share, gain for the cumulative effect of adopting SFAS No. 133 in the first quarter of 2001.

51

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As
previously discussed in theSignificant Eventssection, 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. 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.

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 and expect to sell substantially all of our investments in this operation by the end of 2003.
Through February 28, 2003, we liquidated approximately 85% of our investment portfolio since the beginning of 2002.

Consolidated Nonoperating Income and Expenses

Other Income

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 was about the same in 2001 compared to 2000.

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. Other
income for BGE decreased $7.1 million during 2001 compared to 2000 mostly due to the absence of income on the Calvert Cliffs decommissioning trust fund that was transferred to our merchant energy
business effective July 1, 2000 as a result of electric deregulation.

Fixed Charges

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

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.
Total fixed charges for BGE decreased $29.4 million during 2001 compared to 2000 mostly because of a lower level of debt outstanding primarily due to the transfer of debt to our merchant energy
business effective July 1, 2000 due to the implementation of electric deregulation.

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
inNote 9.

52

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Financial Condition

Cash Flows

Cash provided by operations was $1,020.0 million in 2002 compared to $573.3 million in 2001 and $850.9 million in 2000.

Cash
used in investing activities was $319.8 million in 2002 compared to $1,472.7 million in 2001 and $1,106.5 million in 2000. The decrease in 2002 compared to 2001 was mostly due to
the sale of Orion and COPT that generated $555.4 million in cash proceeds, as well as the liquidation program associated with our investment portfolio and a decrease in capital spending due to the
termination of all planned development projects. This was partially offset by the acquisitions of NewEnergy (net of cash acquired) for $204.8 million in September 2002 and of Alliance (net of cash
acquired) for $16.6 million in December 2002. The increase in 2001 compared to 2000 was mostly due to increased purchases of property, plant and equipment and other capital expenditures including
$382.7 million relating to the net cash paid for the acquisition of Nine Mile Point.

Cash
used in financing activities was $157.6 million in 2002 compared to cash provided by financing activities of $789.1 million in 2001 and $345.6 million in 2000. The decrease in 2002
compared to 2001 was mostly due to higher repayment of debt in 2002 and the issuance of common stock in 2001. This was partially offset by higher issuance of debt during 2002. The increase in 2001
compared to 2000 was mostly due to increased proceeds from the issuance of common stock, an increase in proceeds from the net issuance of short-term borrowings, and a $130.0 million decrease in common
stock dividends paid. These items were partially offset by the issuance of less long-term debt and higher repayments of our long-term debt.

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

Available Sources of Funding

In 2001, we decided to sell certain non-core assets to focus on our core strategies. During 2002, we realized proceeds of over $800 million from the sale of non-core assets and
used these funds to repay both short-term and long-term debt. In addition, during 2002, we issued $2.5 billion of debt and established $1.28 billion of credit facilities resulting in $1.7 billion of
total credit facilities. 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 the $2.5 billion of debt issued in 2002, Constellation Energy has a commercial paper program under which we can issue short-term notes to fund our subsidiaries.
At December 31, 2002, we had approximately $1.5 billion of credit under three facilities as discussed below.

In
June 2002, Constellation Energy arranged a $640 million 364-day revolving credit facility and a $640 million three-year revolving credit facility. We use these two facilities to allow
issuance of commercial paper and letters of credit along with our previously established $188.5 million revolving credit facility that expires in June 2003.

53

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At
December 31, 2002, we had $338.7 million of outstanding letters of credit that results in approximately $1.1 billion of unused credit facilities. These three facilities can issue
letters of credit up to approximately $1.1 billion. Constellation Energy also has access to interim lines of credit as required from time to time to support its outstanding commercial paper.

BGE

BGE maintains $200.0 million in annual committed credit facilities, expiring May through November 2003, in order to allow commercial paper to be issued. As of
December 31, 2002, BGE had no outstanding commercial paper, which results in $200.0 million in unused credit facilities. BGE also has access to interim lines of credit as required from time to time to
support its outstanding commercial paper.

Other Nonregulated Businesses

BGE Home Products & Services maintains a program to sell up to $50 million of receivables.

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

Capital Resources

Our business requires a great deal of capital. Our actual consolidated capital requirements for the years 2000 through 2002, along with the
estimated annual amount for 2003, are shown in the table below.

We will continue to have cash requirements for:



Capital requirements for 2003 and 2004 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 theForward Looking Statementssection.

|                                   |                                            | 2000                                             |       | 2001 |     | 2002  |       | 2003 |    
|---------------------------------- | ------------------------------------------ | ------------------------------------------------ | ----- | ---- | --- | ----- | ----- | ---- | ---
|
|
|Nonregulated Capital Requirements: |                                            |                                                  |       |      |     |       |       |      |    
|                                   | Merchant energy (excludes acquisitions)    |                                                  |       |      |     |       |       |      |    
|                                   |                                            | Construction program                             |       | $    | 537 |       | $     | 697  |    
|                                   |                                            | Steam generators                                 |       |      | 21  |       |       | 53   |    
|                                   |                                            | Environmental controls                           |       |      | 45  |       |       | 89   |    
|                                   |                                            | Continuing requirements (including nuclear fuel) |       |      | 96  | (A)   |       | 205  |    
|                                   |                                           
|                                   | Total merchant energy capital requirements |                                                  |       | 699  |     |       | 1,044 |      |    
|                                   | Other nonregulated capital requirements    |                                                  |       | 131  |     |       | 35    |      |    
|                                   |                                           
|                                   | Total nonregulated capital requirements    |                                                  |       | 830  |     |       | 1,079 |      |    
|                                   |                                           
|Utility Capital Requirements:      |                                            |                                                  |       |      |     |       |       |      |    
|                                   | Regulated electric                         |                                                  |       |      |     |       |       |      |    
|                                   |                                            | Generation                                       |       |      | 73  |       |       |     |    
|                                   |                                            | Steam generators                                 |       |      | 13  |       |       |     |    
|                                   |                                            | Environmental controls                           |       |      | 17  |       |       |     |    
|                                   |                                            | Transmission and distribution                    |       |      | 187 |       |       | 180  |    
|                                   |                                           
|                                   | Total regulated electric                   |                                                  |       | 290  |     |       | 180   |      |    
|                                   | Regulated gas                              |                                                  |       | 60   |     |       | 59    |      |    
|                                   |                                           
|                                   | Total utility capital requirements         |                                                  |       | 350  |     |       | 239   |      |    
|                                   |                                           
|Total capital requirements         |                                            | $                                                | 1,180 |      | $   | 1,318 |       | $    | 923
|                                   |                                           

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

As of the date of this report, we have not completed our 2004 capital budgeting process, but expect our 2004 capital requirements to be approximately $600-700
million.

54

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Capital Requirements

Merchant Energy Business

Our merchant energy business will invest in the following:



The
table on the previous page does not include the financing for the High Desert 830 megawatt gas-fired generation project in California, which is under an operating lease with a term
through February 2006. Under the terms of the lease, we are required to make payments that represent all or a portion of the lease balance if construction is terminated prior to completion or we
default under the lease.

Under
certain circumstances, we may be required to either post cash collateral equal to the outstanding lease balance or we may elect to purchase the property for the outstanding lease
balance. At any time during the term of the lease we have the right to pay off the lease and acquire the asset from the lessor. At December 31, 2002, the outstanding lease balance plus other committed
expenses was approximately $585 million.

Our
wholly owned subsidiary, High Desert Power Project LLC, is supervising the construction of, and leasing, the High Desert project from High Desert Power Trust, an independent special
purpose entity (SPE) created to own and lease the project to our subsidiary. Neither Constellation Energy nor any affiliate owns any equity or other interest in High Desert Power Trust, which is owned
by a consortium of banks and other financial institutions. We provide a guaranty of High Desert Power Project LLC's obligations to the Trust.

The
High Desert Power Project uses an off-balance sheet financing structure through this SPE and currently qualifies as an operating lease. As an operating lease, we do not record any
assets or debt associated with the project in our Consolidated Balance Sheets. In January 2003, the FASB issued Interpretation No. (FIN) 46,Consolidation of Variable Interest
Entities, that will impact the accounting for, but not the cash flows associated with, our High Desert operating lease and the related SPE. Under the interpretation and current
lease structure, we will be required to consolidate the SPE in our Consolidated Balance Sheets as of July 1, 2003, which is the effective date of FIN 46. Had we consolidated this project at December
31, 2002, we would have recorded approximately $488.7 million of development, construction, and capitalized financing costs as an asset and the related financial obligations as a liability in our
Consolidated Balance Sheets. We discuss FIN 46 in more detail inNote 1.

The
lease with the Trust contains several events of default that are commonly found in financings of this type, including failure to make all payments when due, failure to comply with
all covenants, violation of material representations and warranties and change of control. In addition, several events of default are applicable to us as guarantor, including defaults in other
material financing agreements and failure to own 100% of BGE's common stock.

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



If
the lessor sells the property, we guarantee the payment of any difference between the sale proceeds and the lease balance at the time of sale up to a maximum amount of approximately
83% of such lease balance. The lease balance at the end of the term is currently estimated to be $600 million, which represents the estimated cost of the project; however, this may vary based on the
ultimate cost of construction and interest incurred during the construction period.

Regulated Electric and Gas

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

55

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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 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 with a mixture of debt and equity with an overall goal of maintaining a strong investment grade credit profile.

BGE

Funding for utility capital expenditures is expected from internally generated funds. During 2003, we expect our regulated utility business to generate significant excess cash
flows from operations. If necessary, additional funding may be obtained from commercial paper issuances, available capacity under credit facilities, the issuance of long-term debt, trust securities,
or preference stock, and/or from time to time equity contributions from Constellation Energy. During 2002, Constellation Energy made a $200 million capital contribution to BGE. BGE also participates
in a cash pool administered by Constellation Energy as discussed inNote 15.

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 theResults of OperationOther Nonregulated Businessessection.

Committed Amounts

Our total contractual and contingent obligations as of December 31, 2002 are shown in the following table:

|                              |                                  | Payments/Expiration
|----------------------------- | -------------------------------- | -------------------
|
|
|Contractual Obligations       |                                  |                    
|                              | Short-term borrowings            |                    
|                              | Nonregulated long-term debt1     |                    
|                              | BGE long-term debt               |                    
|                              | BGE preference stock             |                    
|                              | Fuel and transportation          |                    
|                              | Purchased capacity and energy2   |                    
|                              | Operating leases                 |                    
|                              | Capital and loan commitments 3   |                    
|                             
|Total contractual obligations |                                  | $                  
|                             
|Contingent Obligations        |                                  |                    
|                              | Letters of credit                |                    
|                              | Guarantees - competitive supply4 |                    
|                              | Other guarantees, net 5          |                    
|                             
|Total contingent obligations  |                                  | $                  
|                             
|Total obligations             |                                  | $                  
|                             

While we included our contingent obligations in the table above, these amounts do not represent incremental consolidated Constellation Energy
obligations; rather, they primarily represent guarantees from one Constellation entity to another. We do not expect to fund the full amounts under the letters of credit and guarantees. Specifically,
the $2,151.0 million guaranteescompetitive supply represent the face amount of these guarantees. However, we do not expect to fund the full amount, as our calculation of the fair
value of obligations covered by these guarantees was $519.8 million at December 31, 2002.

56

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Lease
payments under the High Desert operating lease are reflected in "Other guarantees, net" in the table on the previous page. The lease balance at the end of the 2006 lease term is
currently estimated to be $600 million.

The
table on the previous page does not include the fixed payment portions of our mark-to-market energy assets and liabilities primarily related to capacity payments under tolling
contracts. We discuss the expected settlement terms of these contracts in theCompetitive SupplyMark-to-Market Energy Assets and
Liabilitiessection.

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
origination 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
|------------------------- |  | -------------------------- |  | ----------------------- | --- | ----------------------
|
|BBB/Baa2                  |  | 1                          |  | $                       | 55  |                       
|BBB-/Baa3                 |  | 2                          |  |                         | 125 |                       
|Below investment grade    |  | 3                          |  |                         | 500 |                       

At December 31, 2002, we had approximately $1.3 billion of unused credit facilities and $615.0 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.

In
many cases, customers of our origination and risk management operation rely on the creditworthiness of Constellation Energy. A decline below investment grade by Constellation Energy
would negatively impact the business prospects of that operation.

The
credit facilities of Constellation Energy and BGE have limited material adverse change clauses that only consider a material change in financial condition and are not directly
affected by decreases in credit ratings. If these clauses are violated, the lending institutions can decline making new advances or issuing new letters of credit, but cannot
accelerate existing amounts outstanding. The 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, 2002, the debt to capitalization ratios as defined in the credit agreements were no greater than 57%.

A
BGE credit facility of $50.0 million that expires in August 2003 requires BGE to maintain a ratio of debt to capitalization equal to or less than 70%. At December 31, 2002, the debt to
capitalization ratio for BGE as defined in the credit agreement was 54%. At December 31, 2002, no amount is outstanding under this facility.

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 borrowings inNote 7, long-term debt inNote 8, lease
requirements inNote 10, and commitments and guarantees inNote 11.

57

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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

|                      |  | 2003 |       | 2004 |   | 2005  |   | 2006 |       | 2007 |   | Thereafter |   | Total |       | Fair value at
Dec. 31, 2002
|--------------------- |  | ---- | ----- | ---- | - | ----- | - | ---- | ----- | ---- | - | ---------- | - | ----- | ----- | ---------------------------
|
|
|Short-term debt       |  |      |       |      |   |       |   |      |       |      |   |            |   |       |       |                            
|Variable-rate debt    |  | $    | 10.5  |      | $ |      |   | $    |      |      | $ |           |   | $     |      |                            
|Average interest rate |  |      | 3.61  | %    |   |      |   |      |      |      |   |           |   |       |      |                            
|Long-term debt        |  |      |       |      |   |       |   |      |       |      |   |            |   |       |       |                            
|Variable-rate debt    |  | $    | 5.0   |      | $ | 7.0   |   | $    | 7.5   |      | $ | 120.6      |   | $     | 10.0  |                            
|Average interest rate |  |      | 5.49  | %    |   | 5.45  | % |      | 5.50  | %    |   | 1.75       | % |       | 5.50  | %                          
|Fixed-rate debt       |  | $    | 284.7 | (A)  | $ | 152.0 |   | $    | 343.8 |      | $ | 352.8      |   | $     | 728.1 |                            
|Average interest rate |  |      | 6.50  | %    |   | 5.75  | % |      | 7.72  | %    |   | 5.54       | % |       | 7.00  | %                          

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 operational 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. A number of factors associated with the structure and operation of the electricity markets significantly influence the level and volatility of
prices for energy commodities and related derivative products. We use such commodities and contracts in our merchant energy business, and if we have not hedged the associated financial exposure, this
price volatility could affect our earnings. These factors include:



58

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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:



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 either to generate power using plants with more costly fuel or 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.

Operational Risk

Operational 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 2003, 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. Beginning in July 2002, approximately 1,200 megawatts of industrial customer load moved from BGE's standard offer service to market-based rates. Going forward, our merchant energy
business will supply 100% of the standard offer service to BGE through June 30, 2003 and 90% from July 1, 2003 through June 30, 2006.

As
a result of declines in BGE's standard offer service load and the 2,900 megawatts of natural gas-fired peaking and combined cycle generating facilities recently constructed, we have a
substantial amount of generating capacity that is subject to future changes in wholesale electricity prices and 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 as changes in fuel costs.

Additionally,
if one or more of our generating facilities is not able to produce electricity when required due to operational factors, we may have to forego sales opportunities or
fulfill fixed-price sale commitments through the operation of other more costly generating facilities or through the purchase of energy in the wholesale market at higher prices.

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. Calvert Cliffs
experienced an extended outage to replace the steam generators for Unit 1 during a refueling outage in the spring of 2002, and will experience another extended outage to replace the steam generators
for Unit 2 during a refueling outage in the spring 2003.

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:



59

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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, 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 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 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 mark-to-market energy assets and liabilities over a one-day holding period. Based on the confidence
levels in the table below, we would expect a one-day change in fair value greater than or equal to the daily value at risk at least once per year. Our value at risk was as follows:

|         |  | 99.9% Confidence Level |      | 95% Confidence Level
|-------- |  | ---------------------- | ---- | --------------------
|
|
|
|Year end |  | $                      | 7.4  |                     
|Average  |  |                        | 15.5 |                     
|High     |  |                        | 33.8 |                     
|Low      |  |                        | 4.2  |                     

The high value at risk amount for the year 2001 represents certain hedge contracts entered into in anticipation of closing an offsetting
transaction. When the offsetting transaction closed within several days, the value at risk amount returned to a level more representative of the average for the year.

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

Regulated Electric Business

Effective July 1, 2000, BGE's residential rates are frozen for a six-year period, and its commercial and industrial rates are frozen for four to six years. BGE entered into
standard offer service arrangements with our origination and risk management operation and Allegheny Energy Supply Company to provide the energy and capacity required to meet its standard offer
service obligations through June 30, 2006.

60

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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 inNote 1. At December 31, 2002 and 2001, 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 use credit
policies to manage our credit risk, including utilizing an established credit approval process, monitoring counterparty limits, employing credit mitigation measures such as margin, collateral, or
prepayment arrangements, and using master netting agreements. We measure credit risk as the replacement cost for open energy commodity and derivative positions (both mark-to-market and accrual) plus
amounts owed from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where we have a legally enforceable right
of setoff.

Recently,
several major participants in the energy markets suffered severe declines in their credit ratings or declared bankruptcy. However, as of December 31, 2002, approximately 85% of
our credit portfolio was rated at least investment grade by the major rating agencies, with 3% rated below investment grade and 12% not rated. Of the portion not rated, 84% primarily represents
governmental entities, municipalities, cooperatives, power pools, or other load-serving entities that we assess are equivalent to investment grade based on internal credit ratings.

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

Equity Price Risk

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

A
hypothetical 10% decrease in equity prices would result in an approximate $65 million reduction in the fair value of our financial investments that are classified as trading or
available-for-sale securities. In 2002, the value of our defined benefit pension plan assets decreased by approximately $90 million due to declines in the markets in which plan assets are invested. We
describe our financial investments in more detail inNote 4, and our pension plans inNote 6.

---

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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

61

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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 accountants, audit the financial statements and express their opinion on them. They perform their audit in accordance with auditing
standards generally accepted in the United States of America.

The
Audit Committee of the Board of Directors, which consists of three 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.

|SIGNATURE                                                                         |  | SIGNATURE                                                      
|--------------------------------------------------------------------------------- |  | ---------------------------------------------------------------
|Mayo A. Shattuck III Chairman of the Board,
President and Chief
Executive Officer |  | E. Follin Smith Senior Vice-President &
Chief Financial Officer

REPORT OF INDEPENDENT ACCOUNTANTS

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

In our opinion, the consolidated financial statements listed in the index appearing under Item 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, 2002 and 2001, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2002 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 statement of capitalization
of Constellation Energy Group, Inc. and Subsidiaries and of Baltimore Gas and Electric Company and Subsidiaries as of December 31, 2000, 1999 and 1998, and the related consolidated
statements of income, cash flows, and common shareholders' equity and comprehensive income for the years ended December 31, 1999 and 1998 (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, 2002, 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, 2002, is fairly stated,
in all material respects, in relation to the consolidated financial statements from which it has been derived.

As
discussed inNote 1to 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).

SIGNATURE

PricewaterhouseCoopers
LLP
Baltimore, Maryland
January 29, 2003

62

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CONSOLIDATED STATEMENTS OF INCOME

Constellation Energy Group, Inc. and Subsidiaries

|Year Ended December 31,                                                                                                              |                                                                                | 2002 |         | 2001    |   | 2000  |        
|------------------------------------------------------------------------------------------------------------------------------------ | ------------------------------------------------------------------------------ | ---- | ------- | ------- | - | ----- | -------
|
|
|Revenues                                                                                                                             |                                                                                |      |         |         |   |       |        
|                                                                                                                                     | Nonregulated revenues                                                          |      | $       | 2,166.9 |   | $     | 1,164.9
|                                                                                                                                     | Regulated electric revenues                                                    |      |         | 1,965.6 |   |       | 2,039.6
|                                                                                                                                     | Regulated gas revenues                                                         |      |         | 570.5   |   |       | 674.3  
|                                                                                                                                     |                                                                               
|                                                                                                                                     | Total revenues                                                                 |      |         | 4,703.0 |   |       | 3,878.8
|Expenses                                                                                                                             |                                                                                |      |         |         |   |       |        
|                                                                                                                                     | Operating expenses                                                             |      |         | 3,049.9 |   |       | 2,392.2
|                                                                                                                                     | Workforce reduction costs                                                      |      |         | 62.8    |   |       | 105.7  
|                                                                                                                                     | Impairment losses and other costs                                              |      |         | 25.2    |   |       | 158.8  
|                                                                                                                                     | Contract termination related costs                                             |      |         |        |   |       | 224.8  
|                                                                                                                                     | Depreciation and amortization                                                  |      |         | 481.0   |   |       | 419.1  
|                                                                                                                                     | Taxes other than income taxes                                                  |      |         | 259.2   |   |       | 226.6  
|                                                                                                                                     |                                                                               
|                                                                                                                                     | Total expenses                                                                 |      |         | 3,878.1 |   |       | 3,527.2
|Net Gain on Sales of Investments and Other Assets                                                                                    |                                                                                |      | 261.3   |         |   | 6.2   |        
|                                                                                                                                     |                                                                               
|Income from Operations                                                                                                               |                                                                                |      | 1,086.2 |         |   | 357.8 |        
|Other Income                                                                                                                         |                                                                                |      | 30.5    |         |   | 1.3   |        
|Fixed Charges                                                                                                                        |                                                                                |      |         |         |   |       |        
|                                                                                                                                     | Interest expense                                                               |      |         | 312.3   |   |       | 283.2  
|                                                                                                                                     | Interest capitalized and allowance for borrowed funds used during construction |      |         | (44.0   | ) |       | (57.6  
|                                                                                                                                     | BGE preference stock dividends                                                 |      |         | 13.2    |   |       | 13.2   
|                                                                                                                                     |                                                                               
|                                                                                                                                     | Total fixed charges                                                            |      |         | 281.5   |   |       | 238.8  
|                                                                                                                                     |                                                                               
|Income Before Income Taxes                                                                                                           |                                                                                |      | 835.2   |         |   | 120.3 |        
|Income Taxes                                                                                                                         |                                                                                |      | 309.6   |         |   | 37.9  |        
|                                                                                                                                     |                                                                               
|Income Before Cumulative Effect of Change in Accounting Principle                                                                    |                                                                                |      | 525.6   |         |   | 82.4  |        
|Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes of $5.6 (see Note 1)                                        |                                                                                |      |        |         |   | 8.5   |        
|                                                                                                                                     |                                                                               
|Net Income                                                                                                                           |                                                                                | $    | 525.6   |         | $ | 90.9  |        
|                                                                                                                                     |                                                                               
|Earnings Applicable to Common Stock                                                                                                  |                                                                                | $    | 525.6   |         | $ | 90.9  |        
|                                                                                                                                     |                                                                               
|Average Shares of Common Stock Outstanding                                                                                           |                                                                                |      | 164.2   |         |   | 160.7 |        
|Earnings Per Common Share and Earnings Per Common ShareAssuming Dilution Before Cumulative Effect of Change in Accounting Principle |                                                                                | $    | 3.20    |         | $ | .52   |        
|Cumulative Effect of Change in Accounting Principle                                                                                  |                                                                                |      |        |         |   | .05   |        
|                                                                                                                                     |                                                                               
|Earnings Per Common Share and
Earnings Per Common ShareAssuming Dilution                                                            |                                                                                | $    | 3.20    |         | $ | .57   |        
|                                                                                                                                     |                                                                               

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

63

---

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

|At December 31, |                               | 2002                                                                                     |                                               | 2001     |         
|--------------- | ----------------------------- | ---------------------------------------------------------------------------------------- | --------------------------------------------- | -------- | --------
|
|
|Assets          |                               |                                                                                          |                                               |          |         
|                | Current Assets                |                                                                                          |                                               |          |         
|                |                               | Cash and cash equivalents                                                                |                                               | $        | 615.0   
|                |                               | Accounts receivable (net of allowance for uncollectibles
of$41.9and $22.8, respectively) |                                               |          | 1,247.3 
|                |                               | Trading securities                                                                       |                                               |          | 77.1    
|                |                               | Mark-to-market energy assets                                                             |                                               |          | 144.0   
|                |                               | Risk management assets                                                                   |                                               |          | 72.3    
|                |                               | Fuel stocks                                                                              |                                               |          | 126.5   
|                |                               | Materials and supplies                                                                   |                                               |          | 208.6   
|                |                               | Prepaid taxes other than income taxes                                                    |                                               |          | 57.1    
|                |                               | Other                                                                                    |                                               |          | 153.9   
|                |                              
|                |                               | Total current assets                                                                     |                                               |          | 2,701.8 
|                |                              
|                | Investments and Other Assets  |                                                                                          |                                               |          |         
|                |                               | Real estate projects and investments                                                     |                                               |          | 86.1    
|                |                               | Investments in qualifying facilities and power projects                                  |                                               |          | 439.2   
|                |                               | Investment in Orion Power Holdings, Inc.                                                 |                                               |          |        
|                |                               | Financial investments                                                                    |                                               |          | 36.9    
|                |                               | Nuclear decommissioning trust funds                                                      |                                               |          | 645.4   
|                |                               | Mark-to-market energy assets                                                             |                                               |          | 1,348.2 
|                |                               | Risk management assets                                                                   |                                               |          | 88.8    
|                |                               | Goodwill                                                                                 |                                               |          | 115.9   
|                |                               | Other                                                                                    |                                               |          | 167.8   
|                |                              
|                |                               | Total investments and other assets                                                       |                                               |          | 2,928.3 
|                |                              
|                | Property, Plant and Equipment |                                                                                          |                                               |          |         
|                |                               | Regulated property, plant and equipment                                                  |                                               |          |         
|                |                               |                                                                                          | Plant in service                              |          |         
|                |                               |                                                                                          | Construction work in progress                 |          |         
|                |                               |                                                                                          | Plant held for future use                     |          |         
|                |                              
|                |                               |                                                                                          | Total regulated property, plant and equipment |          |         
|                |                               | Nonregulated generation property, plant and equipment                                    |                                               |          | 6,811.9 
|                |                               | Other nonregulated property, plant and equipment                                         |                                               |          | 242.0   
|                |                               | Nuclear fuel (net of amortization)                                                       |                                               |          | 224.8   
|                |                               | Accumulated depreciation                                                                 |                                               |          | (4,396.8
|                |                              
|                |                               | Net property, plant and equipment                                                        |                                               |          | 7,957.1 
|                |                              
|                | Deferred Charges              |                                                                                          |                                               |          |         
|                |                               | Regulatory assets (net)                                                                  |                                               |          | 405.7   
|                |                               | Other                                                                                    |                                               |          | 136.0   
|                |                              
|                |                               | Total deferred charges                                                                   |                                               |          | 541.7   
|                |                              
|                | Total Assets                  |                                                                                          | $                                             | 14,128.9 |         
|                |                              

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

64

---

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

|At December 31,        |                                                          | 2002                                                     |   | 2001    
|---------------------- | -------------------------------------------------------- | -------------------------------------------------------- | - | --------
|
|
|Liabilities and Equity |                                                          |                                                          |   |         
|                       | Current Liabilities                                      |                                                          |   |         
|                       |                                                          | Short-term borrowings                                    |   | $       
|                       |                                                          | Current portion of long-term debt                        |   |         
|                       |                                                          | Accounts payable                                         |   |         
|                       |                                                          | Mark-to-market energy liabilities                        |   |         
|                       |                                                          | Risk management liabilities                              |   |         
|                       |                                                          | Dividends declared                                       |   |         
|                       |                                                          | Accrued interest                                         |   |         
|                       |                                                          | Other                                                    |   |         
|                      
|                       |                                                          | Total current liabilities                                |   |         
|                      
|                       | Deferred Credits and Other Liabilities                   |                                                          |   |         
|                       |                                                          | Deferred income taxes                                    |   |         
|                       |                                                          | Mark-to-market energy liabilities                        |   |         
|                       |                                                          | Risk management liabilities                              |   |         
|                       |                                                          | Net pension liability                                    |   |         
|                       |                                                          | Postretirement and postemployment benefits               |   |         
|                       |                                                          | Deferred investment tax credits                          |   |         
|                       |                                                          | Other                                                    |   |         
|                      
|                       |                                                          | Total deferred credits and other liabilities             |   |         
|                      
|                       | Capitalization (See Statement of Capitalization)         |                                                          |   |         
|                       |                                                          | Long-term debt                                           |   |         
|                       |                                                          | Minority interests                                       |   |         
|                       |                                                          | BGE preference stock not subject to mandatory redemption |   |         
|                       |                                                          | Common shareholders' equity                              |   |         
|                      
|                       |                                                          | Total capitalization                                     |   |         
|                      
|                       | Commitments, Guarantees, and Contingencies (see Note 11) |                                                          |   |         
|                       | Total Liabilities and Equity                             |                                                          | $ | 14,128.9
|                      

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

65

---

CONSOLIDATED STATEMENTS OF CASH FLOWS

Constellation Energy Group, Inc. and Subsidiaries

|Year Ended December 31,                              |                                                                                                                                                                                                                                                                       | 2002                                                                         |                                              | 2001     |         | 2000   |         
|---------------------------------------------------- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ---------------------------------------------------------------------------- | -------------------------------------------- | -------- | ------- | ------ | --------
|
|
|Cash Flows From Operating Activities                 |                                                                                                                                                                                                                                                                       |                                                                              |                                              |          |         |        |         
|                                                     | Net income                                                                                                                                                                                                                                                            |                                                                              | $                                            | 525.6    |         | $      | 90.9    
|                                                     | Adjustments to reconcile to net cash provided by operating activities                                                                                                                                                                                                 |                                                                              |                                              |          |         |        |         
|                                                     |                                                                                                                                                                                                                                                                       | Cumulative effect of change in accounting principle                          |                                              |          |        |        |         
|                                                     |                                                                                                                                                                                                                                                                       | Depreciation and amortization                                                |                                              |          | 548.0   |        |         
|                                                     |                                                                                                                                                                                                                                                                       | Deferred income taxes                                                        |                                              |          | 148.3   |        |         
|                                                     |                                                                                                                                                                                                                                                                       | Investment tax credit adjustments                                            |                                              |          | (7.9    | )      |         
|                                                     |                                                                                                                                                                                                                                                                       | Deferred fuel costs                                                          |                                              |          | 23.9    |        |         
|                                                     |                                                                                                                                                                                                                                                                       | Pension and postemployment benefits                                          |                                              |          | (116.2  | )      |         
|                                                     |                                                                                                                                                                                                                                                                       | Net gain on sales of investments and other assets                            |                                              |          | (261.3  | )      |         
|                                                     |                                                                                                                                                                                                                                                                       | Workforce reduction costs                                                    |                                              |          | 62.8    |        |         
|                                                     |                                                                                                                                                                                                                                                                       | Impairment losses and other costs                                            |                                              |          | 25.2    |        |         
|                                                     |                                                                                                                                                                                                                                                                       | Contract termination related costs                                           |                                              |          |        |        |         
|                                                     |                                                                                                                                                                                                                                                                       | Deregulation transition cost                                                 |                                              |          |        |        |         
|                                                     |                                                                                                                                                                                                                                                                       | Equity in earnings of affiliates less than (in excess of) dividends received |                                              |          | 67.0    |        |         
|                                                     |                                                                                                                                                                                                                                                                       | Changes in                                                                   |                                              |          |         |        |         
|                                                     |                                                                                                                                                                                                                                                                       |                                                                              | Accounts receivable                          |          |         | (236.8 | )       
|                                                     |                                                                                                                                                                                                                                                                       |                                                                              | Mark-to-market energy assets and liabilities |          |         | (133.7 | )       
|                                                     |                                                                                                                                                                                                                                                                       |                                                                              | Risk management assets and liabilities       |          |         | 58.6   |         
|                                                     |                                                                                                                                                                                                                                                                       |                                                                              | Materials, supplies and fuel stocks          |          |         | (11.7  | )       
|                                                     |                                                                                                                                                                                                                                                                       |                                                                              | Other current assets                         |          |         | 130.3  |         
|                                                     |                                                                                                                                                                                                                                                                       |                                                                              | Accounts payable                             |          |         | 188.4  |         
|                                                     |                                                                                                                                                                                                                                                                       |                                                                              | Other current liabilities                    |          |         | 50.4   |         
|                                                     |                                                                                                                                                                                                                                                                       |                                                                              | Other                                        |          |         | (40.9  | )       
|                                                     |                                                                                                                                                                                                                                                                      
|                                                     | Net cash provided by operating activities                                                                                                                                                                                                                             |                                                                              |                                              | 1,020.0  |         |        | 573.3   
|                                                     |                                                                                                                                                                                                                                                                      
|Cash Flows From Investing Activities                 |                                                                                                                                                                                                                                                                       |                                                                              |                                              |          |         |        |         
|                                                     | Purchases of property, plant and equipment                                                                                                                                                                                                                            |                                                                              |                                              | (831.9   | )       |        | (1,302.5
|                                                     | Acquisitions, net of cash acquired                                                                                                                                                                                                                                    |                                                                              |                                              | (221.4   | )       |        | (382.7  
|                                                     | Contributions to nuclear decommissioning trust funds                                                                                                                                                                                                                  |                                                                              |                                              | (17.6    | )       |        | (22.0   
|                                                     | Payments for structured deal fees                                                                                                                                                                                                                                     |                                                                              |                                              | (51.4    | )       |        |        
|                                                     | Sale of (investment in) Orion                                                                                                                                                                                                                                         |                                                                              |                                              | 454.1    |         |        | 26.2    
|                                                     | Sale of investments and other assets                                                                                                                                                                                                                                  |                                                                              |                                              | 383.9    |         |        | 260.9   
|                                                     | Purchases of marketable equity securities                                                                                                                                                                                                                             |                                                                              |                                              | (0.2     | )       |        | (33.2   
|                                                     | Other investments                                                                                                                                                                                                                                                     |                                                                              |                                              | (35.3    | )       |        | (19.4   
|                                                     |                                                                                                                                                                                                                                                                      
|                                                     | Net cash used in investing activities                                                                                                                                                                                                                                 |                                                                              |                                              | (319.8   | )       |        | (1,472.7
|                                                     |                                                                                                                                                                                                                                                                      
|Cash Flows From Financing Activities                 |                                                                                                                                                                                                                                                                       |                                                                              |                                              |          |         |        |         
|                                                     | Net issuance (maturity) of short-term borrowings                                                                                                                                                                                                                      |                                                                              |                                              | (964.5   | )       |        | 731.4   
|                                                     | Proceeds from issuance of                                                                                                                                                                                                                                             |                                                                              |                                              |          |         |        |         
|                                                     |                                                                                                                                                                                                                                                                       | Long-term debt                                                               |                                              |          | 2,529.3 |        |         
|                                                     |                                                                                                                                                                                                                                                                       | Common stock                                                                 |                                              |          | 28.5    |        |         
|                                                     | Repayment of long-term debt                                                                                                                                                                                                                                           |                                                                              |                                              | (1,627.7 | )       |        | (1,510.2
|                                                     | Common stock dividends paid                                                                                                                                                                                                                                           |                                                                              |                                              | (137.8   | )       |        | (120.7  
|                                                     | Other                                                                                                                                                                                                                                                                 |                                                                              |                                              | 14.6     |         |        | 9.0     
|                                                     |                                                                                                                                                                                                                                                                      
|                                                     | Net cash (used in) provided by financing activities                                                                                                                                                                                                                   |                                                                              |                                              | (157.6   | )       |        | 789.1   
|                                                     |                                                                                                                                                                                                                                                                      
|Net Increase (Decrease) in Cash and Cash Equivalents |                                                                                                                                                                                                                                                                       |                                                                              | 542.6                                        |          |         | (110.3 | )       
|Cash and Cash Equivalents at Beginning of Year       |                                                                                                                                                                                                                                                                       |                                                                              | 72.4                                         |          |         | 182.7  |         
|                                                     |                                                                                                                                                                                                                                                                      
|Cash and Cash Equivalents at End of Year             |                                                                                                                                                                                                                                                                       | $                                                                            | 615.0                                        |          | $       | 72.4   |         
|                                                     |                                                                                                                                                                                                                                                                      
|Other Cash Flow Information:                         |                                                                                                                                                                                                                                                                       |                                                                              |                                              |          |         |        |         
|                                                     | Cash paid during the year for:                                                                                                                                                                                                                                        |                                                                              |                                              |          |         |        |         
|                                                     |                                                                                                                                                                                                                                                                       | Interest (net of amounts capitalized)                                        |                                              | $        | 230.5   |        | $       
|                                                     |                                                                                                                                                                                                                                                                       | Income taxes                                                                 |                                              | $        | 157.8   |        | $       
|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 as discussed further inNote 14. |                                                                             

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

66

---

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME

Constellation Energy Group, Inc. and Subsidiaries

|                                                 |                                  |                                                                                                    |  |   |         |   |   | Accumulated Other Comprehensive Income |       |   |       
|------------------------------------------------ | -------------------------------- | -------------------------------------------------------------------------------------------------- |  | - | ------- | - | - | -------------------------------------- | ----- | - | ------
|
|
|
|
|Balance at December 31, 1999                     |                                  | 149,556                                                                                            |  | $ | 1,494.0 |   | $ | 1,499.1                                |       | $ | 24.4  
|Comprehensive Income                             |                                  |                                                                                                    |  |   |         |   |   |                                        |       |   |       
|                                                 | Net income                       |                                                                                                    |  |   |         |   |   |                                        | 345.3 |   |       
|                                                 | Other comprehensive income (OCI) |                                                                                                    |  |   |         |   |   |                                        |       |   |       
|                                                 |                                  | Reclassification of net gain on sales of securities from OCI to net income, net of taxes of $18.4  |  |   |         |   |   |                                        |       |   |       
|                                                 |                                  | Net unrealized gain on securities, net of taxes of $27.9                                           |  |   |         |   |   |                                        |       |   |       
|                                                 |                                 
|Total Comprehensive Income                       |                                  |                                                                                                    |  |   |         |   |   |                                        |       |   |       
|Common stock dividend declared ($1.68 per share) |                                  |                                                                                                    |  |   |         |   |   | (251.8                                 | )     |   |       
|Common stock issued                              |                                  | 976                                                                                                |  |   | 35.9    |   |   |                                        |       |   |       
|Other                                            |                                  |                                                                                                    |  |   | 8.8     |   |   | (0.3                                   | )     |   |       
|                                                 |                                 
|Balance at December 31, 2000                     |                                  | 150,532                                                                                            |  |   | 1,538.7 |   |   | 1,592.3                                |       |   | 43.0  
|Comprehensive Income                             |                                  |                                                                                                    |  |   |         |   |   |                                        |       |   |       
|                                                 | Net income                       |                                                                                                    |  |   |         |   |   |                                        | 90.9  |   |       
|                                                 | Other comprehensive income       |                                                                                                    |  |   |         |   |   |                                        |       |   |       
|                                                 |                                  | Cumulative effect of change in accounting principle, net of taxes of $22.6                         |  |   |         |   |   |                                        |       |   |       
|                                                 |                                  | Reclassification of net gain on sales of securities from OCI to net income, net of taxes of $15.7  |  |   |         |   |   |                                        |       |   |       
|                                                 |                                  | Net unrealized gain on securities, net of taxes of $87.5                                           |  |   |         |   |   |                                        |       |   |       
|                                                 |                                  | Net unrealized gain on hedging instruments, net of taxes of $65.6                                  |  |   |         |   |   |                                        |       |   |       
|                                                 |                                  | Minimum pension liability, net of taxes of $29.3                                                   |  |   |         |   |   |                                        |       |   |       
|                                                 |                                 
|Total Comprehensive Income                       |                                  |                                                                                                    |  |   |         |   |   |                                        |       |   |       
|Common stock dividend declared ($.48 per share)  |                                  |                                                                                                    |  |   |         |   |   | (77.1                                  | )     |   |       
|Common stock issued                              |                                  | 13,176                                                                                             |  |   | 504.4   |   |   |                                        |       |   |       
|Other                                            |                                  |                                                                                                    |  |   | (0.9    | ) |   | 5.4                                    |       |   |       
|                                                 |                                 
|Balance at December 31, 2001                     |                                  | 163,708                                                                                            |  |   | 2,042.2 |   |   | 1,611.5                                |       |   | 189.9 
|Comprehensive Income                             |                                  |                                                                                                    |  |   |         |   |   |                                        |       |   |       
|                                                 | Net income                       |                                                                                                    |  |   |         |   |   |                                        | 525.6 |   |       
|                                                 | Other comprehensive income       |                                                                                                    |  |   |         |   |   |                                        |       |   |       
|                                                 |                                  | Reclassification of net gain on sales of securities from OCI to net income, net of taxes of $87.7  |  |   |         |   |   |                                        |       |   |       
|                                                 |                                  | Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $10.9 |  |   |         |   |   |                                        |       |   |       
|                                                 |                                  | Net unrealized loss on securities, net of taxes of $28.6                                           |  |   |         |   |   |                                        |       |   |       
|                                                 |                                  | Net unrealized loss on hedging instruments, net of taxes of $31.7                                  |  |   |         |   |   |                                        |       |   |       
|                                                 |                                  | Minimum pension liability, net of taxes of $77.2                                                   |  |   |         |   |   |                                        |       |   |       
|                                                 |                                 
|Total Comprehensive Income                       |                                  |                                                                                                    |  |   |         |   |   |                                        |       |   |       
|Common stock dividend declared ($.96 per share)  |                                  |                                                                                                    |  |   |         |   |   | (157.6                                 | )     |   |       
|Common stock issued                              |                                  | 1,135                                                                                              |  |   | 28.5    |   |   |                                        |       |   |       
|Other                                            |                                  |                                                                                                    |  |   | 8.2     |   |   | (1.9                                   | )     |   |       
|                                                 |                                 
|Balance at December 31, 2002                     |                                  | 164,843                                                                                            |  | $ | 2,078.9 |   | $ | 1,977.6                                |       | $ | (194.2
|                                                 |                                 

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

67

---

CONSOLIDATED STATEMENTS OF CAPITALIZATION

Constellation Energy Group, Inc. and Subsidiaries

|At December 31,      |                                                                                                                                                                        | 2002                                                               |                                                                       | 2001   |        
|-------------------- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ------------------------------------------------------------------ | --------------------------------------------------------------------- | ------ | -------
|
|
|Long-Term Debt       |                                                                                                                                                                        |                                                                    |                                                                       |        |        
|                     | Long-term debt of Constellation Energy                                                                                                                                 |                                                                    |                                                                       |        |        
|                     |                                                                                                                                                                        | Floating rate notes, due January 17, 2002                          |                                                                       | $      |       
|                     |                                                                                                                                                                        | 77/8% Notes, due April 1, 2005                                     |                                                                       |        | 300.0  
|                     |                                                                                                                                                                        | 6.35% Fixed Rate Notes, due April 1, 2007                          |                                                                       |        | 600.0  
|                     |                                                                                                                                                                        | 6.125% Fixed Rate Notes, due September 1, 2009                     |                                                                       |        | 500.0  
|                     |                                                                                                                                                                        | 7.00% Fixed Rate Notes, due April 1, 2012                          |                                                                       |        | 700.0  
|                     |                                                                                                                                                                        | 7.60% Fixed Rate Notes, due April 1, 2032                          |                                                                       |        | 700.0  
|                     |                                                                                                                                                                       
|                     |                                                                                                                                                                        | Total long-term debt of Constellation Energy                       |                                                                       |        | 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                              |        |        
|                     |                                                                                                                                                                        |                                                                    | Port facilities loan, due June 1, 2013                                |        |        
|                     |                                                                                                                                                                        |                                                                    | Adjustable rate pollution control loan, due July 1, 2014              |        |        
|                     |                                                                                                                                                                        |                                                                    | 5.55% Pollution control revenue refunding loan, due July 15, 2014     |        |        
|                     |                                                                                                                                                                        |                                                                    | Economic development loan, due December 1, 2018                       |        |        
|                     |                                                                                                                                                                        |                                                                    | 6.00% Pollution control revenue refunding loan, due April 1, 2024     |        |        
|                     |                                                                                                                                                                        |                                                                    | Floating rate pollution control loan, due June 1, 2027                |        |        
|                     |                                                                                                                                                                        |                                                                    | 51/2% Installment series, due July 15, 2002                           |        |        
|                     |                                                                                                                                                                        | District Cooling facilities loan, due December 1, 2031             |                                                                       |        | 25.0   
|                     |                                                                                                                                                                        | Loans under revolving credit agreements                            |                                                                       |        | 51.7   
|                     |                                                                                                                                                                        | 11% Installment note, due November 7, 2006                         |                                                                       |        |       
|                     |                                                                                                                                                                        | Mortgage and construction loans                                    |                                                                       |        |        
|                     |                                                                                                                                                                        |                                                                    | Floating rate mortgage notes and construction loans, due through 2005 |        |        
|                     |                                                                                                                                                                        |                                                                    | 4.25% Mortgage note, due March 15, 2009                               |        |        
|                     |                                                                                                                                                                       
|                     |                                                                                                                                                                        | Total long-term debt of nonregulated businesses                    |                                                                       |        | 349.8  
|                     |                                                                                                                                                                       
|                     | First Refunding Mortgage Bonds of BGE                                                                                                                                  |                                                                    |                                                                       |        |        
|                     |                                                                                                                                                                        | 71/4% Series, due July 1, 2002                                     |                                                                       |        |       
|                     |                                                                                                                                                                        | 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  
|                     |                                                                                                                                                                        | Remarketed floating rate series, due September 1, 2006             |                                                                       |        | 111.5  
|                     |                                                                                                                                                                        | 71/2% Series, due January 15, 2007                                 |                                                                       |        | 123.5  
|                     |                                                                                                                                                                        | 65/8% Series, due March 15, 2008                                   |                                                                       |        | 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                        |                                                                       |        | 904.9  
|                     |                                                                                                                                                                       
|                     | Other long-term debt of BGE                                                                                                                                            |                                                                    |                                                                       |        |        
|                     |                                                                                                                                                                        | 5.25% Notes, due December 15, 2006                                 |                                                                       |        | 300.0  
|                     |                                                                                                                                                                        | Floating rate reset notes, due February 5, 2002                    |                                                                       |        |       
|                     |                                                                                                                                                                        | Medium-term notes, Series B                                        |                                                                       |        | 12.1   
|                     |                                                                                                                                                                        | Medium-term notes, Series C                                        |                                                                       |        | 25.5   
|                     |                                                                                                                                                                        | Medium-term notes, Series D                                        |                                                                       |        | 68.0   
|                     |                                                                                                                                                                        | Medium-term notes, Series E                                        |                                                                       |        | 199.5  
|                     |                                                                                                                                                                        | Medium-term notes, Series G                                        |                                                                       |        | 140.0  
|                     |                                                                                                                                                                        | 6.75% Remarketable or redeemable securities, due December 15, 2012 |                                                                       |        |       
|                     |                                                                                                                                                                       
|                     |                                                                                                                                                                        | Total other long-term debt of BGE                                  |                                                                       |        | 745.1  
|                     |                                                                                                                                                                       
|                     | 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                                                                                                                                       |                                                                    |                                                                       | (9.7   | )      
|                     | Current portion of long-term debt                                                                                                                                      |                                                                    |                                                                       | (426.2 | )      
|                     |                                                                                                                                                                       
|Total long-term debt |                                                                                                                                                                        | $                                                                  | 4,613.9                                                               |        | $      
|                     |                                                                                                                                                                       

See Notes to Consolidated Financial Statements.

continued on next page

68

---

CONSOLIDATED STATEMENTS OF CAPITALIZATION

Constellation Energy Group, Inc. and Subsidiaries

|At December 31,             |                                                                                                                                                                                                                                                                                                                                                                                                                                                                              | 2002                                                                                  |         | 2001   
|--------------------------- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ------------------------------------------------------------------------------------- | ------- | -------
|
|
|Minority Interests          |                                                                                                                                                                                                                                                                                                                                                                                                                                                                              | $                                                                                     | 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, not callable prior to July 1, 2003   |         |        
|                            |                                                                                                                                                                                                                                                                                                                                                                                                                                                                              | 6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 |         |        
|                            |                                                                                                                                                                                                                                                                                                                                                                                                                                                                              | 6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 |         |        
|                            |                                                                                                                                                                                                                                                                                                                                                                                                                                                                              | 6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 |         |        
|                           
|                            |                                                                                                                                                                                                                                                                                                                                                                                                                                                                              | Total preference stock not subject to mandatory redemption                            |         |        
|                           
|Common Shareholders' Equity |                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |                                                                                       |         |        
|                            | Common stock without par value, 250,000,000 shares authorized; 164,842,708 and 163,707,950 shares issued and outstanding at December 31, 2002 and 2001, respectively. (At December 31, 2002, 18,000,000 shares were reserved
for the long-term incentive plans, 11,451,868 shares were reserved for the Shareholder Investment Plan, 1,806,100 shares were reserved for the continuous offering programs, and 1,505,863 shares were reserved for the employee savings plan.) |                                                                                       |         | 2,078.9
|                            | Retained earnings                                                                                                                                                                                                                                                                                                                                                                                                                                                            |                                                                                       |         | 1,977.6
|                            | Accumulated other comprehensive (loss) income                                                                                                                                                                                                                                                                                                                                                                                                                                |                                                                                       |         | (194.2 
|                           
|                            | Total common shareholders' equity                                                                                                                                                                                                                                                                                                                                                                                                                                            |                                                                                       |         | 3,862.3
|                           
|Total Capitalization        |                                                                                                                                                                                                                                                                                                                                                                                                                                                                              | $                                                                                     | 8,771.5 |        
|                           

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

69

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CONSOLIDATED STATEMENTS OF INCOME

Baltimore Gas and Electric Company and Subsidiaries

|Year Ended December 31,             |                                                       | 2002                               |       | 2001    |         | 2000  |        
|----------------------------------- | ----------------------------------------------------- | ---------------------------------- | ----- | ------- | ------- | ----- | -------
|
|
|Revenues                            |                                                       |                                    |       |         |         |       |        
|                                    | Electric revenues                                     |                                    | $     | 1,966.0 |         | $     | 2,040.0
|                                    | Gas revenues                                          |                                    |       | 581.3   |         |       | 680.7  
|                                    |                                                      
|                                    | Total revenues                                        |                                    |       | 2,547.3 |         |       | 2,720.7
|Expenses                            |                                                       |                                    |       |         |         |       |        
|                                    | Operating Expenses                                    |                                    |       |         |         |       |        
|                                    |                                                       | Electric fuel and purchased energy |       |         | 1,080.7 |       |        
|                                    |                                                       | Gas purchased for resale           |       |         | 316.7   |       |        
|                                    |                                                       | Operations and maintenance         |       |         | 355.3   |       |        
|                                    |                                                       | Workforce reduction costs          |       |         | 35.3    |       |        
|                                    | Depreciation and amortization                         |                                    |       | 221.6   |         |       | 221.0  
|                                    | Taxes other than income taxes                         |                                    |       | 171.4   |         |       | 173.8  
|                                    |                                                      
|                                    | Total expenses                                        |                                    |       | 2,181.0 |         |       | 2,408.9
|                                    |                                                      
|Income from Operations              |                                                       |                                    | 366.3 |         |         | 311.8 |        
|Other Income                        |                                                       |                                    | 10.7  |         |         | 0.4   |        
|Fixed Charges                       |                                                       |                                    |       |         |         |       |        
|                                    | Interest expense                                      |                                    |       | 142.1   |         |       | 156.2  
|                                    | Allowance for borrowed funds used during construction |                                    |       | (1.5    | )       |       | (1.6   
|                                    |                                                      
|                                    | Total fixed charges                                   |                                    |       | 140.6   |         |       | 154.6  
|                                    |                                                      
|Income Before Income Taxes          |                                                       |                                    | 236.4 |         |         | 157.6 |        
|Income Taxes                        |                                                       |                                    |       |         |         |       |        
|                                    | Current                                               |                                    |       | 67.4    |         |       | 62.4   
|                                    | Deferred                                              |                                    |       | 28.0    |         |       | 0.2    
|                                    | Investment tax credit adjustments                     |                                    |       | (2.1    | )       |       | (2.3   
|                                    |                                                      
|                                    | Total income taxes                                    |                                    |       | 93.3    |         |       | 60.3   
|                                    |                                                      
|Net Income                          |                                                       |                                    | 143.1 |         |         | 97.3  |        
|Preference Stock Dividends          |                                                       |                                    | 13.2  |         |         | 13.2  |        
|                                    |                                                      
|Earnings Applicable to Common Stock |                                                       | $                                  | 129.9 |         | $       | 84.1  |        
|                                    |                                                      

See Notes to Consolidated Financial Statements.

70

---

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

|At December 31, |                  | 2002                                                                                     |                        | 2001    |         
|--------------- | ---------------- | ---------------------------------------------------------------------------------------- | ---------------------- | ------- | --------
|
|
|Assets          |                  |                                                                                          |                        |         |         
|                | Current Assets   |                                                                                          |                        |         |         
|                |                  | Cash and cash equivalents                                                                |                        | $       | 10.2    
|                |                  | Accounts receivable (net of allowance for uncollectibles of$11.5and $13.4, respectively) |                        |         | 357.5   
|                |                  | Investment in cash pool, affiliated company                                              |                        |         | 338.1   
|                |                  | Accounts receivable, affiliated companies                                                |                        |         | 131.2   
|                |                  | Fuel stocks                                                                              |                        |         | 40.6    
|                |                  | Materials and supplies                                                                   |                        |         | 31.8    
|                |                  | Prepaid taxes other than income taxes                                                    |                        |         | 42.0    
|                |                  | Other                                                                                    |                        |         | 10.3    
|                |                 
|                |                  | Total current assets                                                                     |                        |         | 961.7   
|                |                 
|                | Other Assets     |                                                                                          |                        |         |         
|                |                  | Receivable, affiliated company                                                           |                        |         | 63.3    
|                |                  | Other                                                                                    |                        |         | 85.9    
|                |                 
|                |                  | Total other assets                                                                       |                        |         | 149.2   
|                |                 
|                | Utility Plant    |                                                                                          |                        |         |         
|                |                  | Plant in service                                                                         |                        |         |         
|                |                  |                                                                                          | Electric               |         |         
|                |                  |                                                                                          | Gas                    |         |         
|                |                  |                                                                                          | Common                 |         |         
|                |                 
|                |                  |                                                                                          | Total plant in service |         |         
|                |                  | Accumulated depreciation                                                                 |                        |         | (1,851.4
|                |                 
|                |                  | Net plant in service                                                                     |                        |         | 3,101.0 
|                |                  | Construction work in progress                                                            |                        |         | 118.3   
|                |                  | Plant held for future use                                                                |                        |         | 4.5     
|                |                 
|                |                  | Net utility plant                                                                        |                        |         | 3,223.8 
|                |                 
|                | Deferred Charges |                                                                                          |                        |         |         
|                |                  | Regulatory assets (net)                                                                  |                        |         | 405.7   
|                |                  | Other                                                                                    |                        |         | 39.5    
|                |                 
|                |                  | Total deferred charges                                                                   |                        |         | 445.2   
|                |                 
|                | Total Assets     |                                                                                          | $                      | 4,779.9 |         
|                |                 

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

71

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CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

|At December 31,        |                                                          | 2002                                                                                                                                             |   | 2001    |        
|---------------------- | -------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------------------------------------ | - | ------- | -------
|
|
|Liabilities and Equity |                                                          |                                                                                                                                                  |   |         |        
|                       | Current Liabilities                                      |                                                                                                                                                  |   |         |        
|                       |                                                          | Current portions of long-term debt                                                                                                               |   | $       | 420.7  
|                       |                                                          | Accounts payable                                                                                                                                 |   |         | 103.2  
|                       |                                                          | Accounts payable, affiliated companies                                                                                                           |   |         | 85.6   
|                       |                                                          | Customer deposits                                                                                                                                |   |         | 54.2   
|                       |                                                          | Accrued taxes                                                                                                                                    |   |         | 9.0    
|                       |                                                          | Accrued interest                                                                                                                                 |   |         | 31.4   
|                       |                                                          | Accrued vacation costs                                                                                                                           |   |         | 19.5   
|                       |                                                          | Other                                                                                                                                            |   |         | 30.2   
|                       |                                                         
|                       |                                                          | Total current liabilities                                                                                                                        |   |         | 753.8  
|                       |                                                         
|                       | Deferred Credits and Other Liabilities                   |                                                                                                                                                  |   |         |        
|                       |                                                          | Deferred income taxes                                                                                                                            |   |         | 528.9  
|                       |                                                          | Postretirement and postemployment benefits                                                                                                       |   |         | 278.0  
|                       |                                                          | Deferred investment tax credits                                                                                                                  |   |         | 20.5   
|                       |                                                          | Decommissioning of federal uranium enrichment facilities                                                                                         |   |         | 14.6   
|                       |                                                          | Other                                                                                                                                            |   |         | 13.9   
|                       |                                                         
|                       |                                                          | Total deferred credits and other liabilities                                                                                                     |   |         | 855.9  
|                       |                                                         
|                       | Long-term Debt                                           |                                                                                                                                                  |   |         |        
|                       |                                                          | First refunding mortgage bonds of BGE                                                                                                            |   |         | 904.9  
|                       |                                                          | Other long-term debt of BGE                                                                                                                      |   |         | 745.1  
|                       |                                                          | Company obligated mandatorily redeemable trust preferred
securities of subsidiary trust holding solely 7.16% debentures
of BGE due June 30, 2038 |   |         | 250.0  
|                       |                                                          | Long-term debt of nonregulated businesses                                                                                                        |   |         | 25.0   
|                       |                                                          | Unamortized discount and premium                                                                                                                 |   |         | (5.2   
|                       |                                                          | Current portion of long-term debt                                                                                                                |   |         | (420.7 
|                       |                                                         
|                       |                                                          | Total long-term debt                                                                                                                             |   |         | 1,499.1
|                       |                                                         
|                       | Minority Interest                                        |                                                                                                                                                  |   | 19.4    |        
|                       | Preference Stock Not Subject to Mandatory Redemption     |                                                                                                                                                  |   | 190.0   |        
|                       | Common Shareholder's Equity                              |                                                                                                                                                  |   |         |        
|                       |                                                          | Common stock                                                                                                                                     |   |         | 912.2  
|                       |                                                          | Retained earnings                                                                                                                                |   |         | 549.5  
|                       |                                                         
|                       |                                                          | Total common shareholder's equity                                                                                                                |   |         | 1,461.7
|                       |                                                         
|                       | Commitments, Guarantees, and Contingencies (see Note 11) |                                                                                                                                                  |   |         |        
|                       | Total Liabilities and Equity                             |                                                                                                                                                  | $ | 4,779.9 |        
|                       |                                                         

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

72

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CONSOLIDATED STATEMENTS OF CASH FLOWS

Baltimore Gas and Electric Company and Subsidiaries

|Year Ended December 31,                              |                                                                                                                                                                                                                   | 2002                                                |                                        | 2001   |       | 2000  |       
|---------------------------------------------------- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | --------------------------------------------------- | -------------------------------------- | ------ | ----- | ----- | ------
|
|
|Cash Flows From Operating Activities                 |                                                                                                                                                                                                                   |                                                     |                                        |        |       |       |       
|                                                     | Net income                                                                                                                                                                                                        |                                                     | $                                      | 143.1  |       | $     | 97.3  
|                                                     | Adjustments to reconcile to net cash provided by operating activities                                                                                                                                             |                                                     |                                        |        |       |       |       
|                                                     |                                                                                                                                                                                                                   | Depreciation and amortization                       |                                        |        | 224.4 |       |       
|                                                     |                                                                                                                                                                                                                   | Deferred income taxes                               |                                        |        | 28.0  |       |       
|                                                     |                                                                                                                                                                                                                   | Investment tax credit adjustments                   |                                        |        | (2.1  | )     |       
|                                                     |                                                                                                                                                                                                                   | Deferred fuel costs                                 |                                        |        | 23.9  |       |       
|                                                     |                                                                                                                                                                                                                   | Pension and postemployment benefits                 |                                        |        | (40.7 | )     |       
|                                                     |                                                                                                                                                                                                                   | Allowance for equity funds used during construction |                                        |        | (2.8  | )     |       
|                                                     |                                                                                                                                                                                                                   | Workforce reduction costs                           |                                        |        | 35.3  |       |       
|                                                     |                                                                                                                                                                                                                   | Changes in                                          |                                        |        |       |       |       
|                                                     |                                                                                                                                                                                                                   |                                                     | Accounts receivable                    |        |       | (62.3 | )     
|                                                     |                                                                                                                                                                                                                   |                                                     | Receivables, affiliated companies      |        |       | 52.2  |       
|                                                     |                                                                                                                                                                                                                   |                                                     | Materials, supplies and fuel stocks    |        |       | 13.0  |       
|                                                     |                                                                                                                                                                                                                   |                                                     | Other current assets                   |        |       | 27.8  |       
|                                                     |                                                                                                                                                                                                                   |                                                     | Accounts payable                       |        |       | 39.6  |       
|                                                     |                                                                                                                                                                                                                   |                                                     | Accounts payable, affiliated companies |        |       | (7.0  | )     
|                                                     |                                                                                                                                                                                                                   |                                                     | Other current liabilities              |        |       | (11.2 | )     
|                                                     |                                                                                                                                                                                                                   |                                                     | Other                                  |        |       | 33.2  |       
|                                                     |                                                                                                                                                                                                                  
|                                                     | Net cash provided by operating activities                                                                                                                                                                         |                                                     |                                        | 494.4  |       |       | 371.8 
|                                                     |                                                                                                                                                                                                                  
|Cash Flows From Investing Activities                 |                                                                                                                                                                                                                   |                                                     |                                        |        |       |       |       
|                                                     | Utility construction expenditures (excluding equity portion of AFC)                                                                                                                                               |                                                     |                                        | (216.7 | )     |       | (236.4
|                                                     | Investment in cash pool at parent                                                                                                                                                                                 |                                                     |                                        | 101.0  |       |       | (441.1
|                                                     | Nuclear fuel expenditures                                                                                                                                                                                         |                                                     |                                        |       |       |       |      
|                                                     | Contributions to nuclear decommissioning trust fund                                                                                                                                                               |                                                     |                                        |       |       |       |      
|                                                     | Other                                                                                                                                                                                                             |                                                     |                                        | (17.0  | )     |       | (20.9 
|                                                     |                                                                                                                                                                                                                  
|                                                     | Net cash used in investing activities                                                                                                                                                                             |                                                     |                                        | (132.7 | )     |       | (698.4
|                                                     |                                                                                                                                                                                                                  
|Cash Flows From Financing Activities                 |                                                                                                                                                                                                                   |                                                     |                                        |        |       |       |       
|                                                     | Net maturity of short-term borrowings                                                                                                                                                                             |                                                     |                                        |       |       |       | (32.1 
|                                                     | Proceeds from issuance of long-term debt                                                                                                                                                                          |                                                     |                                        |       |       |       | 532.1 
|                                                     | Repayment of long-term debt                                                                                                                                                                                       |                                                     |                                        | (575.5 | )     |       | (394.1
|                                                     | Preference stock dividends paid                                                                                                                                                                                   |                                                     |                                        | (13.2  | )     |       | (13.2 
|                                                     | Distribution from (to) parent                                                                                                                                                                                     |                                                     |                                        | 200.0  |       |       | 250.0 
|                                                     | Other                                                                                                                                                                                                             |                                                     |                                        | (0.2   | )     |       |      
|                                                     |                                                                                                                                                                                                                  
|                                                     | Net cash (used in) provided by financing activities                                                                                                                                                               |                                                     |                                        | (388.9 | )     |       | 342.7 
|                                                     |                                                                                                                                                                                                                  
|Net (Decrease) Increase in Cash and Cash Equivalents |                                                                                                                                                                                                                   |                                                     | (27.2                                  | )      |       | 16.1  |       
|Cash and Cash Equivalents at Beginning of Year       |                                                                                                                                                                                                                   |                                                     | 37.4                                   |        |       | 21.3  |       
|                                                     |                                                                                                                                                                                                                  
|Cash and Cash Equivalents at End of Year             |                                                                                                                                                                                                                   | $                                                   | 10.2                                   |        | $     | 37.4  |       
|                                                     |                                                                                                                                                                                                                  
|Other Cash Flow Information                          |                                                                                                                                                                                                                   |                                                     |                                        |        |       |       |       
|                                                     | Cash paid during the year for:                                                                                                                                                                                    |                                                     |                                        |        |       |       |       
|                                                     |                                                                                                                                                                                                                   | Interest (net of amounts capitalized)               |                                        | $      | 147.5 |       | $     
|                                                     |                                                                                                                                                                                                                   | Income taxes                                        |                                        | $      | 36.6  |       | $     
|Noncash Investing and Financing Activities:          |                                                                                                                                                                                                                  
|                                                     | On July 1, 2000, BGE transferred $1,578.4 million of generation assets, net of associated liabilities, to nonregulated affiliates of Constellation Energy as a result of the deregulation of electric
generation. |                                                    

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

73

---



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1Significant Accounting Policies

Nature of Our Business

Constellation Energy Group, Inc. (Constellation Energy) is a North American energy company that conducts its business through various subsidiaries including a merchant
energy business and Baltimore Gas and Electric Company (BGE). Our merchant energy business is a competitive provider of energy solutions for large customers. BGE is a regulated electric and gas public
transmission and distribution utility company with a service territory that covers the City of Baltimore and all or part of ten counties in central Maryland. 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. References in this report
to the "utility business" are to BGE.

Consolidation Policy

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

Consolidation

We use consolidation when we own a majority of the voting stock of the subsidiary. This means the accounts of our subsidiaries are combined with our accounts. We eliminate
intercompany balances and transactions when we consolidate these accounts. We discuss the implications of the Financial Accounting Standards Board (FASB) Interpretation No. 46, Consolidation of Variable Interest
Entitieson our future consolidation policy later in this Note.

The Equity Method

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



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

The Cost Method

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

Regulation of Utility Business

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

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

We
summarize and discuss our regulatory assets and liabilities further inNote 5.

Use of Accounting Estimates

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



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

74

---

Reclassifications

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

Revenues

Nonregulated Businesses

We record nonregulated business revenues using two methods of accounting: accrual accounting and mark-to-market accounting. We use accrual accounting
for our merchant energy business transactions, including non-trading long-term power sales contracts that are not subject to mark-to-market accounting.
Transactions subject to accrual accounting include the generation or purchase and sale of electricity and gas as part of our physical delivery activities. Under accrual accounting, we record revenues
in the period earned for services rendered, commodities or products delivered, or contracts settled.

We
use mark-to-market accounting for energy trading activities and for derivatives and other contracts for which we are not permitted to use accrual accounting or
hedge accounting. We discuss our use of hedge accounting in theRisk Management and Hedging Activitiessection later in this Note. These
mark-to-market activities include derivative and (prior to EITF 02-3) non-derivative contracts for energy and other energy-related commodities. Under
the mark-to-market method of accounting, we record the fair value of energy contracts as mark-to-market energy assets and liabilities at the time of
contract execution. We record reserves to reflect uncertainties associated with certain estimates inherent in the determination of fair value. To the extent possible, we utilize market-based data
together with quantitative methods for both measuring the risks 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.



Mark-to-market
revenues include:



We
record the changes in mark-to-market energy assets and liabilities on a net basis in "Nonregulated revenues" in our Consolidated Statements of Income. At
December 31, 2002, mark-to-market energy assets and liabilities consist of a combination of energy and energy-related derivative and non-derivative
contracts. While some of these contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and
are valued using modeling techniques to determine expected future market prices, contract quantities, or both. The market prices and quantities used to determine fair value reflect management's best
estimate considering various factors, including closing exchange and over-the-counter quotations, time value, and volatility factors. However, 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.

During
2002, the FASB issued EITF 02-3,Recognition and Reporting of Gains and Losses on Energy Trading Contracts Under EITF Issues
No. 98-10 and No. 00-17that changed the accounting for energy contracts. These changes include requiring the accrual method of accounting
for energy contracts that are not derivatives and clarifying when gains or losses can be recognized at the inception of derivative contracts. We discuss EITF 02-3 in more detail in the Recently Issued Accounting
Standardssection later in this Note.

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

We
also include equity in earnings from our investments in qualifying facilities and power projects in revenues.

Regulated Utility

We record utility revenues when we provide service to customers.

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Fuel and Purchased Energy Costs

We incur costs for:



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

Fuel Used to Generate Electricity and Purchases of Electricity From Others

We assemble a variety of power supply resources, including baseload, intermediate, and peaking plants that we own, as well as a variety of power supply contracts that may have
similar characteristics, in order to enable us to meet our customers' energy requirements, which vary on an hourly basis. We purchase power when our load-serving requirements exceed the
amount of power available from our supply resources or when it is more economic to do so than to operate our power plants. The amount of power purchased depends on a number of factors, including the
capacity and availability of our power plants, the level of customer demand, and the relative economics of generating power versus purchasing power from the spot market.

Our
accrual-basis third-party fuel and purchased energy expenses were as follows:

|                          |  | 2002 |         | 2001 |   | 2000 
|------------------------- |  | ---- | ------- | ---- | - | -----
|
|
|Fuel and Purchased Energy |  | $    | 1,144.2 |      | $ | 479.6

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



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

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

Natural Gas

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

Risk Management and Hedging Activities

Market Risks

We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price and transportation costs of electricity, natural gas, and
other commodities as discussed further inNote 12. SFAS No. 133,as amended by SFAS
No. 138,Accounting for Certain Derivative Instruments and Certain Hedging Activities,requires that we recognize all derivatives not qualifying
for the normal purchase and normal sale exemption in our Consolidated Balance Sheets at fair value. Changes in the value of derivatives that are not hedges must be recorded in earnings. Under SFAS
No. 133, changes in the value of derivatives designated as cash-flow hedges that are effective in offsetting the variability in cash flows of forecasted transactions are recognized
in other comprehensive income until the forecasted transactions occur. The ineffective portion of changes in fair value of derivatives used as cash-flow hedges is immediately recognized in
earnings.

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



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

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

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Interest Rate Swaps

We use interest rate swaps to manage our interest rate exposures associated with new debt issuances. These swaps are in anticipation of planned financing transactions and are
designated as cash-flow hedges under SFAS No. 133, with our gains or losses recorded in "Risk management assets or liabilities" in our Consolidated Balance Sheets and "Accumulated
other comprehensive income," in our Consolidated Statements of Common Shareholders' Equity and Consolidated Statements of Capitalization. Any gain or loss on the hedges will be reclassified from
"Accumulated other comprehensive income" into "Interest expense" and be included in earnings during the periods in which the interest payments being hedged occur.

Commodity Prices

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

Merchant Energy Business

Our origination and risk management operation manages market risk on a portfolio basis, subject to established risk management policies. Our origination and risk management
operation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and purchases of fuel.

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

Regulated Gas Business

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

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

Credit Risk

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

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

Electric
and gas utilities, cooperatives, and energy marketers comprise the majority of counterparties underlying our assets from our origination and risk management activities. We held
cash collateral from counterparties totaling $50.1 million as of December 31, 2002 and $3.5 million as of December 31, 2001. These amounts are included in "Other deferred
credits and other liabilities" in our Consolidated Balance Sheets.

Taxes

We summarize our income taxes inNote 9. Our subsidiary income taxes are computed on a separate return basis. As you read
this section, it may be helpful to refer toNote 9.

Income Tax Expense

We have two categories of income taxescurrent and deferred. We describe each of these below:



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Investment Tax Credits

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

Deferred Income Tax Assets and Liabilities

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

A
portion of our total deferred income tax liability relates to our regulated utility business, but has not been reflected in the rates we charge our customers. We refer to this portion
of the liability as "Income taxes recoverable through future rates (net)." We have recorded that portion of the net liability as a regulatory asset in our Consolidated Balance Sheets. We discuss this
further inNote 5.

State and Local Taxes

State and local income taxes are included in "Income taxes" in our Consolidated Statements of Income.

We
also pay Maryland public service company franchise tax on transmission, distribution, and delivery of electricity and natural gas. We include the franchise tax in "Taxes other than
income taxes" in our Consolidated Statements of Income.

Earnings Per Share

Basic earnings per common share (EPS) is computed by dividing earnings applicable to common stock by the weighted-average number of common shares outstanding for the year.
Diluted EPS reflects the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Our
dilutive common stock equivalent shares consist of stock options. Stock options to purchase approximately 4.1 million shares in 2002, approximately 0.1 million shares in 2001, and
approximately 1.4 million shares in 2000 were not dilutive and were excluded from the computation of diluted EPS for these respective years.

Stock-Based Compensation

Under our long-term incentive plans, we granted stock options, performance and service-based restricted stock, and equity to officers, key employees, and members of
the Board of Directors. We discuss this in more detail inNote 13.

As
permitted by SFAS No. 123,Accounting for Stock-Based Compensation, we measure our stock-based compensation in accordance with
Accounting Principles Board Opinion (APB) No. 25,Accounting for Stock Issued to Employees,and related interpretations.

Our
stock options are granted with an exercise price equal to the market value of the stock at the date of grant. Accordingly, no compensation expense is recorded for these awards.
However, when we grant options subject to a contingency, we recognize compensation expense when options granted have an exercise price less than the market value of the underlying common stock on the
date the contingency is satisfied. We amortize compensation expense for restricted stock over the performance/service period, which is typically a one to five year period.

The
following table illustrates the effect on net income and earnings per share had we applied the fair value recognition provision of SFAS No. 123 to all outstanding stock option
and stock awards in each year.

|                                                                                                                             |                     | 2002 |       | 2001 |   | 2000 |    
|---------------------------------------------------------------------------------------------------------------------------- | ------------------- | ---- | ----- | ---- | - | ---- | ---
|
|
|Net income, as reported                                                                                                      |                     | $    | 525.6 |      | $ | 90.9 |    
|Add: Stock-based compensation expense included in reported net income, net of related tax effects                            |                     |      | 6.1   |      |   | (6.1 | )  
|Deduct: Stock-based compensation expense determined under fair value based method for all awards, net of related tax effects |                     |      | (16.8 | )    |   | (0.9 | )  
|                                                                                                                             |                    
|Pro-forma net income                                                                                                         |                     | $    | 514.9 |      | $ | 83.9 |    
|                                                                                                                             |                    
|Earnings per share:                                                                                                          |                     |      |       |      |   |      |    
|                                                                                                                             | Basicas reported   |      | $     | 3.20 |   | $    | .57
|                                                                                                                             | Basicpro forma     |      | $     | 3.14 |   | $    | .52
|                                                                                                                             | Dilutedas reported |      | $     | 3.20 |   | $    | .57
|                                                                                                                             | Dilutedpro forma   |      | $     | 3.13 |   | $    | .52

In
the table above, the stock-based compensation expense included in reported net income, net of related tax effects is as follows:



Cash and Cash Equivalents

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

Inventory

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

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Real Estate Projects and Investments

InNote 4, we summarize the real estate projects and investments that are in our Consolidated Balance Sheets. At
December 31, 2002, the projects and investments primarily consist of:



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

Financial Investments and Trading Securities

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

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

Trading Securities

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

Available-for-Sale Securities

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

In
addition, our other nonregulated businesses classified some of their investments in marketable equity securities as available-for-sale securities.

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

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

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.

We
determine if long-lived assets are impaired by comparing their undiscounted expected future cash flows to their carrying amount in our accounting records. We would record
an impairment loss if the undiscounted expected future cash flows from an asset were less than the carrying amount of the asset. We are also required to evaluate our equity-method and
cost-method investments (for example, in partnerships that own power projects) for impairment. 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.

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

Goodwill

Goodwill is the excess of the purchase price of an acquisition 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 the evaluation of goodwill for impairment at
least annually or more frequently if events and circumstances indicate that the asset might be impaired. We discuss our acquisitions inNote 14.

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

We report our property, plant and equipment at its original cost, unless impaired under the provisions of SFAS No. 144.

Our
original costs include:



We
own an undivided interest in the Keystone and Conemaugh electric generating plants in Western Pennsylvania, as well as in the transmission line that transports the plants' output to
the joint owners' service territories. Our ownership interests in these plants are 20.99% in Keystone and 10.56% in Conemaugh. These ownership interests represented a net investment of
$168 million at December 31, 2002 and $148 million at December 31, 2001. Each owner is responsible for financing its proportionate share of the plants' working funds.
Working funds are used for operating expenses and capital expenditures. Operating expenses related to these plants are included in "Operating Expenses" in our Consolidated Statements of Income.
Capital costs related to these plants are included in "Nonregulated generation property, plant and equipment" in our Consolidated Balance Sheets.

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The
"Nonregulated generation property, plant and equipment" in our Consolidated Balance Sheets includes nonregulated generation construction work in progress of $237.2 million at
December 31, 2002 and $1,146.2 million at December 31, 2001.

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

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

Depreciation Expense

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



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

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

Amortization Expense

Amortization is an accounting process of reducing an amount in our Consolidated Balance Sheets evenly over a period of time that approximates the useful life of the related
item. When we reduce amounts in our Consolidated Balance Sheets, we increase amortization expense in our Consolidated Statements of Income.

Nuclear Fuel

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

Nuclear Decommissioning

We record an expense and a reserve for the costs expected to be incurred in the future to decommission Calvert Cliffs based on a sinking fund methodology. The accumulated
decommissioning reserve is recorded in "Accumulated depreciation" in our Consolidated Balance Sheets. The total reserve was $333.7 million at December 31, 2002 and $304.6 million
at December 31, 2001. Our contributions to the nuclear decommissioning trust funds were $17.6 million for 2002, $22.0 million for 2001, and $13.2 million for 2000.

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

We
recorded a reserve for the costs expected to be incurred in the future to decommission Nine Mile Point under the discounted future cash flows methodology. The total reserve was
$242.1 million at December 31, 2002 and $224.4 million at December 31, 2001. We determined that the decommissioning trust funds established for Nine Mile Point are
adequately funded to cover the future costs to decommission the plant and as such, no contributions were made to the trust funds during the years ended December 31, 2002 and December 31,
2001.

In
accordance with Nuclear Regulatory Commission (NRC) regulations, we maintain external decommissioning trusts to fund the costs expected to be incurred to decommission Calvert Cliffs
and Nine Mile Point. The NRC requires utilities to provide financial assurance that they will accumulate sufficient funds to pay for the cost of nuclear decommissioning. The assets in the trusts are
reported in "Nuclear decommissioning trust funds" in our Consolidated Balance Sheets.

We
classify the investments in the nuclear decommissioning trust funds as available-for-sale securities, and we report these investments at fair value in our
Consolidated Balance Sheets as previously discussed in this Note. Investments by nuclear decommissioning trust funds are guided by the "prudent man" investment principle. The funds are prohibited from
investing in Constellation Energy or its affiliates and any other entity owning a nuclear power plant.

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

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Capitalized Interest and Allowance for Funds Used During Construction

Capitalized Interest

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

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

Allowance for Funds Used During Construction (AFC)

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

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

Long-Term Debt

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

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

Accounting Standards Adopted

SFAS No. 148

In December 2002, the Financial Accounting Standards Board (FASB) issued SFAS No. 148, Accounting for Stock-Based
CompensationTransition and Disclosurean amendment of FASB Statement No. 123.SFAS No. 148 provides alternative methods of transition for
a voluntary change to fair value-based methods of accounting for stock-based employee compensation. The Statement also amends the disclosure requirements of SFAS No. 123 to require
prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The
provisions of the Statement were effective for financial statements for fiscal years ending after December 15, 2002.

Recently Issued Accounting Standards

SFAS No. 143

In 2001, the FASB issued SFAS No. 143,Accounting for Asset Retirement Obligations.SFAS No. 143 provides the
accounting requirements for recognizing legal obligations associated with the retirement of tangible long-lived assets. This statement requires a cumulative effect of a change in
accounting principle to be reported upon initial adoption and is effective for fiscal years beginning after June 15, 2002, with early adoption permitted. In January 2003, we recognized a
net after-tax gain of approximately $68 million in accordance with this statement.

Substantially
all of this net gain relates to the impact of adopting SFAS No. 143 on the measurement of the liability for the decommissioning of our Calvert Cliffs nuclear power
plant. Losses on the adoption of SFAS No. 143 in other areas of our business are offset by the gain relating to the decommissioning of our Nine Mile Point nuclear power plant. The Calvert
Cliffs' gain is primarily due to using a longer discount period as a result of license extension. The existing liability for the decommissioning of Calvert Cliffs was determined in accordance with
ratemaking treatment established by the Maryland PSC and is based on a previous decommissioning cost estimate that contemplated decommissioning being completed at a point in time much closer to the
expiration of the plant's original operating license.

As
discussed earlier in this Note, we use the composite depreciation method for certain generating facilities and for our utility business. This method is currently an acceptable method
of accounting under generally accepted accounting principles and is widely-used in the energy, transportation, and telecommunication industries. Under the composite depreciation method,
the anticipated costs of removing assets upon retirement are provided for over the life of those assets as a component of depreciation expense.

However,
the accounting profession has recently determined that SFAS No. 143 precludes the recognition of expected costs of retiring assets in excess of anticipated salvage
proceeds as a component of depreciation expense or accumulated depreciation unless they are legal obligations under SFAS No. 143. Instead, we must recognize these costs as incurred.

We
currently are evaluating the impact of this new guidance on our implementation of SFAS No. 143 and on our financial results. For our merchant energy business, we expect the
elimination of cost of removal in excess of anticipated salvage proceeds from accumulated depreciation to increase the $68 million after-tax gain we recorded in January 2003
discussed above. On a comparable basis, we expect depreciation expense for 2003 and future years to be lower than prior years since the depreciation expense will no longer include a component for
anticipated cost of removal in excess of salvage. Also, effective January 1, 2003 we will only record those asset removal costs that represent legal obligations under SFAS No. 143 prior
to their being incurred.

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As
of the date of this report, we cannot determine the ultimate impact on the cumulative effect adjustment under SFAS No. 143 given the new accounting guidance. However, we expect
the impact of this determination to be material to our financial results.

We
do not expect the adoption of SFAS No. 143 to be material to BGE's financial results. BGE is required by the Maryland PSC to use the composite depreciation method under
regulatory accounting. As a result, we expect the impact of the new guidance to be limited to a balance sheet reclassification of cost of removal from accumulated depreciation to regulatory assets and
liabilities.

SFAS No. 146

In July 2002, the FASB issued SFAS No. 146,Accounting for Exit or Disposal Activities. SFAS No. 146
addresses significant issues regarding the recognition, measurement, and reporting of costs that are associated with exit and disposal activities, including restructuring activities that are currently
accounted for under EITF 94-3. The provisions of the Statement will be effective for disposal activities initiated after December 31, 2002, with early application encouraged. We
will reflect the requirements of this statement in any exit or disposal initiatives after its effective date.

FIN 45

In November 2002, the FASB issued Interpretation No. (FIN) 45,Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others.This Interpretation provides the disclosures to be made by a guarantor in interim and annual financial statements about
obligations under certain guarantees. The Interpretation also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation.
The initial recognition and measurement requirements are effective prospectively for guarantees issued or modified after December 31, 2002. However, the disclosure requirements of the
interpretation are effective for this Form 10-K and are included inNote 11.

FIN 46

In January 2003, the FASB issued FIN 46,Consolidation of Variable Interest Entities, that addresses conditions when an
entity should be consolidated based upon variable interests rather than voting interests. Variable interests are ownership interests or contractual relationships that enable the holder to share in the
financial risks and rewards resulting from the activities of a Variable Interest Entity (VIE). A VIE is a corporation, partnership, trust, or any other legal structure used for business purposes that
either does not have equity investors with voting rights or has equity investors that do not provide sufficient financial resources for the entity to support its activities.

In
order to apply FIN 46, we must evaluate every entity with which we are involved through variable interests to determine whether the entity is a VIE and, if it is, whether or not we
are the primary beneficiary of the entity. The primary beneficiary of a VIE is the entity that receives the majority of the entity's expected losses, residual returns, or both. FIN 46 requires us to
disclose information about significant variable interests we hold and to consolidate a VIE for which we are the primary beneficiary. As a result, FIN 46 could result in consolidation of an entity that
we are associated with other than by (and even in the absence of) a voting ownership interest.

The
requirements of FIN 46 apply immediately to all VIEs created after January 31, 2003 and are effective beginning in the third quarter of 2003 for all VIEs created before
February 1, 2003. At the time of initially applying FIN 46 to previously unconsolidated VIEs, we will remove from our Consolidated Balance Sheets any previously recognized amounts related to
those entities and record the carrying value of the assets, liabilities, and minority interest as reflected in their financial statements. The difference between the net amount added to the
Consolidated Balance Sheets and the amounts removed (if any) upon initial adoption of FIN 46 must be recorded in earnings as the cumulative effect of an accounting change.

Based
upon our initial review of entities with which we are involved through variable interests, we believe that some of these entities are VIEs for which we will have to make
disclosures or which we will be required to consolidate when we apply FIN 46 in the third quarter of 2003. The VIEs for which we are the primary beneficiary (and therefore will have to consolidate)
include the High Desert Power Project, a geothermal power project, the Safe Harbor Water Power Corporation, and an office building in Annapolis, Maryland, that we partially occupy. The other VIEs with
which we are involved (but not as primary beneficiary) include certain other power projects and fuel processing facilities.

Our
variable interests in these entities generally consist of equity investments and, in some instances, guarantees of the entities' debt or the value of the entities' assets. The
following is summary information about these entities as of December 31, 2002:

|                             |  | Primary
Beneficiary |     | Significant
Interest |   | Total
|---------------------------- |  | ------------------- | --- | -------------------- | - | -----
|
|
|Total assets                 |  | $                   | 802 |                      | $ | 472  
|Total liabilities            |  |                     | 618 |                      |   | 419  
|Our ownership interest       |  |                     | 124 |                      |   | 19   
|Other ownership interests    |  |                     | 60  |                      |   | 34   
|Our maximum exposure to loss |  |                     | 662 |                      |   | 68   

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We
believe that the net amount we will add to our Consolidated Balance Sheets when we consolidate VIEs for which we are the primary beneficiary is approximately equal to our recorded
investment and will not result in recording a cumulative effect of an accounting change upon initial adoption of FIN 46. The maximum exposure to loss represents the loss that we would incur if our
investment in all of these entities were to become worthless and we were required to fund the full amount of all guarantees associated with these entities. Our maximum exposure to loss as of
December 31, 2002 consists of the following:



We
assess the risk of a loss equal to our maximum exposure to be remote.

EITF 02-3

On October 25, 2002, the EITF reached a consensus on Issue 02-3,Recognition and Reporting of Gains and Losses on Energy Trading
Contracts Under EITF Issues No. 98-10 and No. 00-17, that changed the accounting for certain energy contracts. The main provisions of EITF
02-3 are as follows:



Applying
EITF 02-3 will not affect our cash flows or our accounting for new load-serving contracts for which we have been using accrual accounting since early
2002. Additionally, we continued to mark existing non-derivative energy-related contracts to market for the remainder of 2002. However, EITF 02-3 requires us to record a
non-cash, cumulative effect adjustment to convert these non-derivative mark-to-market contracts to accrual accounting no later than January 1,
2003.

We
reviewed our portfolio of mark-to-market contracts to identify the contracts that are subject to the requirements of EITF 02-3. The primary
contracts that are affected are our full requirements load-serving contracts and unit-contingent power purchase contracts, which are not derivatives. The majority of these
contracts are in Texas and New England and were entered into prior to the shift to accrual accounting earlier in 2002. Additionally, we reviewed derivatives we use as supply sources and hedges of
contracts that are subject to EITF 02-3. To the extent permitted by SFAS No. 133, we designated derivative contracts used to fulfill our load-serving contracts as either
normal purchases or cash flow hedges under SFAS No. 133 effective January 1, 2003.

We
summarize the impact on our Consolidated Balance Sheets of applying EITF 02-3 on January 1, 2003 as follows:

|                                                                                                 |                                 | Assets |         | Liabilities |   | Net     |       
|------------------------------------------------------------------------------------------------ | ------------------------------- | ------ | ------- | ----------- | - | ------- | ------
|
|
|Mark-to-market energy contracts                                                                  |                                 |        |         |             |   |         |       
|                                                                                                 | Current                         |        | $       | 144.0       |   | $       | 94.1  
|                                                                                                 | Noncurrent                      |        |         | 1,348.2     |   |         | 881.5 
|                                                                                                 |                                
|                                                                                                 | Total                           |        |         | 1,492.2     |   |         | 975.6 
|Other                                                                                            |                                 |        |         |             |   |         |       
|                                                                                                 | Current                         |        |         | 85.7        |   |         | 56.8  
|                                                                                                 | Noncurrent                      |        |         | 24.2        |   |         | 2.5   
|                                                                                                 |                                
|                                                                                                 | Total                           |        |         | 109.9       |   |         | 59.3  
|                                                                                                 |                                
|Balance at December 31, 2002                                                                     |                                 |        | 1,602.1 |             |   | 1,034.9 |       
|Impact of EITF 02-3 Adoption                                                                     |                                 |        |         |             |   |         |       
|Non-derivative net asset reversed as cumulative effect of a change in accounting principle       |                                 |        |         |             |   |         |       
|                                                                                                 | Mark-to-market energy contracts |        |         | (494.7      | ) |         | (119.8
|                                                                                                 | Other                           |        |         | (109.9      | ) |         | (59.3 
|                                                                                                 |                                
|Total non-derivative net asset reversed as cumulative effect of a change in accounting principle |                                 |        | (604.6  | )           |   | (179.1  | )     
|Derivatives designated as hedges                                                                 |                                 |        | (88.3   | )           |   | (94.4   | )     
|Derivatives designated as normal purchases and sales                                             |                                 |        | (192.6  | )           |   | (128.3  | )     
|                                                                                                 |                                
|Mark-to-market derivatives remaining after adoption of EITF 02-3 on January 1, 2003              |                                 | $      | 716.6   |             | $ | 633.1   |       
|                                                                                                 |                                

83

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On January 1, 2003, we recorded the $425.5 million non-derivative net asset removed from our Consolidated Balance Sheets as a cumulative
effect of a change in accounting principle, which will reduce our 2003 net income by $263 million. The $425.5 million represents $374.9 million of non-derivative
contracts recorded as "Mark-to-market energy assets and liabilities" and $50.6 million of "Other assets and liabilities" from the re-designation of Texas
contracts to accrual accounting earlier in 2002. The fair value of these contracts will be recognized in earnings as power is delivered.

Additionally,
on January 1, 2003, we reclassified the fair value of derivatives designated as hedges as "Risk management assets and liabilities" in the balance sheet and will
account for these hedges in accordance with the provisions of SFAS No. 133. At that time, we also reclassified the fair value of derivatives designated as normal purchases and normal sales as
"Other assets and liabilities" in the balance sheet and will account for these contracts on the accrual basis, with the fair value amortized into earnings over the lives of the underlying contracts.

---

2Impairment Losses, Workforce Reduction, Contract Termination, and Other Special Items

|2002 Events                                       |                                                                        |   |       |       |  
|------------------------------------------------- | ---------------------------------------------------------------------- | - | ----- | ----- | -
|
|
|
|Workforce reduction costs:                        |                                                                        |   |       |       |  
|                                                  | Costs associated with 2001 programs                                    |   | $     | (50.8 | )
|                                                  | Costs associated with programs initiated in 2002                       |   |       | (12.0 | )
|                                                  |                                                                       
|                                                  | Total workforce reduction costs                                        |   |       | (62.8 | )
|Impairment losses and other costs:                |                                                                        |   |       |       |  
|                                                  | Impairments of investments in qualifying facilities and power projects |   |       | (14.4 | )
|                                                  | Costs associated with exit of BGE Home merchandise stores              |   |       | (9.0  | )
|                                                  | Impairments of real estate and international investments               |   |       | (1.8  | )
|                                                  |                                                                       
|                                                  | Total impairment losses and other costs                                |   |       | (25.2 | )
|Net gain on sales of investments and other assets |                                                                        |   | 261.3 |       |  
|                                                  |                                                                       
|Total special items                               |                                                                        | $ | 173.3 |       | $
|                                                  |                                                                       

Workforce Reduction Costs

During 2002, we incurred costs related to workforce reduction efforts initiated in the fourth quarter of 2001 as discussed in this Note and additional initiatives undertaken in
the third quarter of 2002. We discuss these costs in more detail below.

Costs associated with 2001 Programs

In 2002, we recorded $63.7 million of net workforce reduction costs associated with our 2001 workforce initiatives as discussed below. The $63.7 million included
$50.8 million recognized as expense, of which BGE recognized $33.8 million. The remaining $12.9 million was recognized by BGE as a regulatory asset related to its gas business as
discussed inNote 5.



In
2002, we completed the 2001 workforce reduction programs. Accordingly, no involuntary severance liability recorded under EITF 94-3,Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)remained at December 31,
2002.

Costs associated with 2002 Programs

In 2002, we recorded $12.0 million of expenses for anticipated involuntary severance costs in accordance with EITF 94-3 associated with new workforce
reduction initiatives as follows:



84

---



At
December 31, 2002, the involuntary severance liability recorded under EITF 94-3 for our 2002 workforce reduction programs was $12.0 million.

Impairment Losses and Other Costs

Investments in Qualifying Facilities and Power Projects

In the third quarter of 2002, our merchant energy business recorded impairment losses on certain of the investments in qualifying facilities and power projects totaling
$14.4 million under the provisions of APB No. 18. We describe these investments inNote 4. The provisions of APB No. 18
require that an impairment loss be recognized when an investment experiences a loss in value that is other than temporary as discussed inNote 1.

During
the third quarter of 2002, we performed an analysis of whether any of the investments were impaired. As a result of our analysis, we concluded that the declines in value of
particular investments in certain qualifying facilities and power projects were other than temporary in nature under the provisions of APB No. 18 and we recognized the following losses in 2002:



Closing of BGE Home Retail Merchandise Stores

In September 2002, we announced our decision to close our BGE Home retail merchandise stores. In connection with that decision, we recognized approximately
$9.5 million in exit costs. We recognized $2.9 million related to expected severance costs for 93 employees and $2.9 million of costs in connection with the termination of leases
for the eight stores and other exit costs in accordance with EITF 94-3.

We
also recognized $3.2 million for the write-off of unamortized leasehold improvements in accordance with SFAS No. 144, and $0.5 million for the
write-down of inventory to a lower-of-cost-or-market valuation in accordance with Accounting Research Bulletin No. 43, Restatement and Revision of Accounting Research Bulletins. The
$0.5 million is included in "Operating expenses" in our Consolidated Statements of
Income.

Real Estate and International Investments

As discussed in the2001 Eventssection on the next page, we changed our strategy from an intent to hold to an intent to sell
for certain of our non-core assets in 2001. During 2002, we determined that the fair value of several real estate projects and our investment in a South American generation project
declined below their respective book values due to deteriorating market conditions for these projects. Accordingly, we recorded losses that totaled $1.8 million for these projects in accordance
with SFAS No. 144 and APB No. 18.

Net Gain on Sales of Investments and Other Assets

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

85

---

In
the fourth quarter of 2001, we announced our decision to focus efforts and capital on core domestic energy businesses and undertook a plan to sell a number of non-core
businesses and investments. In 2002, we made further progress on this initiative, and recognized approximately $5.8 million in net gains from the sale of several non-core assets
including:



2001 Events

|                                                      |                                                                         | Pre-
Tax |        | After-
Tax |  
|----------------------------------------------------- | ----------------------------------------------------------------------- | -------- | ------ | ---------- | -
|
|
|Workforce reduction costs:                            |                                                                         |          |        |            |  
|                                                      | Voluntary termination benefitsVSERP                                    |          | $      | (70.1      | )
|                                                      | Settlement and curtailment charges                                      |          |        | (16.3      | )
|                                                      | Involuntary severance accrual                                           |          |        | (19.3      | )
|                                                      |                                                                        
|                                                      | Total workforce reduction costs                                         |          |        | (105.7     | )
|Contract termination related costs                    |                                                                         |          | (224.8 | )          |  
|Impairment losses and other costs:                    |                                                                         |          |        |            |  
|Cancellation of domestic power projects               |                                                                         |          | (46.9  | )          |  
|                                                      | Impairments of real estate, senior-living and international investments |          |        | (107.3     | )
|                                                      | Reduction of financial investment                                       |          |        | (4.6       | )
|                                                      |                                                                        
|                                                      | Total impairment losses and other costs                                 |          |        | (158.8     | )
|Net gain on the sales of investments and other assets |                                                                         |          | 6.2    |            |  
|                                                      |                                                                        
|Total special items                                   |                                                                         | $        | (483.1 | )          | $
|                                                      |                                                                        

Workforce Reduction Costs

Voluntary Special Early Retirement ProgramsVSERP

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

Since
employees electing to participate in the age 55 or older VSERP had to make their elections by the end of 2001, the cost of that program was reflected in 2001. The
$70.1 million in the above table reflects the portion of the total cost of that program charged to expense for the 507 employees that elected to participate. BGE recorded $37.9 million
of this amount. BGE also recorded $13.7 million on its balance sheet as a regulatory asset related to its gas business as discussed in Note 5.

Settlement and Curtailment Charges

In connection with the age 55 or older VSERP, a significant number of the participants in our nonqualified pension plans retired. As a result, we recognized a settlement loss
of approximately $10.5 million and a curtailment loss of approximately $5.8 million for those plans in accordance with SFAS No. 88. BGE recorded $6.6 million of this
amount. Additional details on the VSERP and their impact on our pension and postretirement benefit plans are discussed inNote 6.

Involuntary Severance Accrual

The voluntary programs were designed, offered, and timed to minimize the number of employees who would be involuntarily severed under our overall workforce reduction plan. Our
workforce reduction plan identified 435 jobs to be eliminated over and above position reductions expected to be satisfied through the age 55 or older VSERP and was specific as to company,
organizational unit, and position. However, the number of employees that would elect to voluntarily retire under the age 50 to 54 VSERP and how many would thereafter be involuntarily severed was not
known until after the election period of the VSERP ended in February 2002.

In
accordance with EITF 94-3, the Company recognized a liability of $25.1 million at December 31, 2001 for the targeted number of involuntary terminations that
would have resulted if no employees elected the age 50 to 54 VSERP. The $19.3 million in the table above represents involuntary severance charged to expense in 2001 in connection with our
workforce reduction programs. BGE recorded $12.5 million of this amount. BGE also recorded $5.8 million on its balance sheet as a regulatory asset related to its gas business as
discussed inNote 5.

86

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Contract Termination Related Costs

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

We
also announced the termination of our power business services agreement with Goldman Sachs. We paid Goldman Sachs a total of $355 million, representing $196.7 million to
terminate the power business services agreement with our origination and risk management operation and $159 million previously recognized as a payable for services rendered under the agreement.

In
addition, we terminated a software agreement we had whereby Goldman Sachs would provide maintenance, support, and minor upgrades to our risk management and trading system. We
recognized $17.6 million in expense in the fourth quarter of 2001 representing the unamortized prepaid costs related to this agreement. Finally, we incurred approximately $10.5 million
in employee-related expenses and advisory costs from investment bankers and legal counsel. In total, we recognized expenses of approximately $224.8 million in the fourth quarter of 2001
relating to the termination of our relationship with Goldman Sachs and our decision not to separate.

Impairment Losses and Other Costs

Cancellation of Domestic Power Projects

In the fourth quarter of 2001, our merchant energy business recorded impairments of $46.9 million primarily due to $40.8 million in impairments associated with
the termination of our planned development projects in Texas, California, Florida, and Massachusetts not under construction. We decided to terminate our development projects due to the expected excess
generation capacity in most domestic markets and the significant decline in the forward market prices of electricity. The impairments include amounts paid for the purchase of four turbines related to
these development projects. In addition, we recognized $6.1 million for an other than temporary decline in the value of our investment in a waste burning power plant in Michigan where operating
cash flows are not sufficient to pay existing debt service and we are not likely to recover our equity interest in this investment.

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

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



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

Reduction of Financial Investment

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

87

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Net Gain on Sales of Investments and Other Assets

During 2001, our other nonregulated businesses recognized $49.5 million on the sale of non-core assets, including a $14.9 million gain on the sale of
one million shares of our Orion investment and $34.6 million on the sales of other financial investments.

In
addition, in 2001, we sold our Guatemalan power plant operations to an affiliate of Duke Energy International, LLC, the international business unit of Duke Energy. Through this sale,
Duke Energy acquired Grupo Generador de Guatemala y Cia., S.C.A., which owns two generating plants at Esquintla and Lake Amatitlan in Guatemala. The combined capacity of the plants is 167 megawatts.

We
decided to sell our Guatemalan operations to focus our efforts on our core energy businesses. As a result of this transaction, we are no longer committed to making significant future
capital investments in a non-core operation. We recorded a $43.3 million loss on this sale.

2000 Events

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

In
addition, we recognized $78.1 million pre-tax, or $47.2 million after-tax, gains including $15.7 million pre-tax, or
$9.5 million after-tax, on the sale of two million shares of our Orion investment and $62.4 million pre-tax, or $37.7 million after-tax, on the
sales of other financial investments.

---

3Information by Operating Segment

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



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



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. We decided to sell certain non-core assets and accelerated the exit strategies of other
projects. We sold certain non-core assets in 2002 and closed our retail merchandise stores in December 2002.

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

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

88

---

|                                                    |  | Merchant Energy Business |         | Regulated Electric Business |   | Regulated Gas Business |  | Other Nonregulated Businesses |         | Unallocated Corporate Items and Eliminations |   | Consolidated
|--------------------------------------------------- |  | ------------------------ | ------- | --------------------------- | - | ---------------------- |  | ----------------------------- | ------- | -------------------------------------------- | - | ------------
|
|
|2002                                                |  |                          |         |                             |   |                        |  |                               |         |                                              |   |             
|Unaffiliated revenues                               |  | $                        | 1,629.5 |                             | $ | 1,965.6                |  | $                             | 570.5   |                                              | $ | 537.4       
|Intersegment revenues                               |  |                          | 1,136.2 |                             |   | 0.4                    |  |                               | 10.8    |                                              |   |            
|                                                   
|Total revenues                                      |  |                          | 2,765.7 |                             |   | 1,966.0                |  |                               | 581.3   |                                              |   | 537.4       
|Depreciation and amortization                       |  |                          | 242.8   |                             |   | 174.2                  |  |                               | 47.4    |                                              |   | 16.6        
|Fixed charges                                       |  |                          | 102.0   |                             |   | 128.4                  |  |                               | 25.9    |                                              |   | 25.2        
|Income tax expense                                  |  |                          | 127.2   |                             |   | 67.1                   |  |                               | 22.4    |                                              |   | 92.9        
|Net income (a)                                      |  |                          | 247.2   |                             |   | 99.3                   |  |                               | 31.1    |                                              |   | 148.0       
|Segment assets                                      |  |                          | 8,866.0 |                             |   | 3,565.1                |  |                               | 1,140.4 |                                              |   | 913.0       
|Capital expenditures                                |  |                          | 641.0   |                             |   | 167.0                  |  |                               | 50.0    |                                              |   | 65.0        
|2001                                                |  |                          |         |                             |   |                        |  |                               |         |                                              |   |             
|Unaffiliated revenues                               |  | $                        | 614.3   |                             | $ | 2,039.6                |  | $                             | 674.3   |                                              | $ | 550.6       
|Intersegment revenues                               |  |                          | 1,151.2 |                             |   | 0.4                    |  |                               | 6.4     |                                              |   | 2.0         
|                                                   
|Total revenues                                      |  |                          | 1,765.5 |                             |   | 2,040.0                |  |                               | 680.7   |                                              |   | 552.6       
|Depreciation and amortization                       |  |                          | 174.9   |                             |   | 173.3                  |  |                               | 47.7    |                                              |   | 23.2        
|Fixed charges                                       |  |                          | 25.8    |                             |   | 135.8                  |  |                               | 28.5    |                                              |   | 48.7        
|Income tax expense (benefit)                        |  |                          | 25.2    |                             |   | 36.8                   |  |                               | 25.7    |                                              |   | (49.8       
|Cumulative effect of change in accounting principle |  |                          |        |                             |   |                       |  |                               |        |                                              |   | 8.5         
|Net income (loss) (b)                               |  |                          | 93.1    |                             |   | 50.9                   |  |                               | 37.5    |                                              |   | (90.6       
|Segment assets                                      |  |                          | 8,123.9 |                             |   | 3,764.9                |  |                               | 1,104.2 |                                              |   | 1,314.0     
|Capital expenditures                                |  |                          | 1,044.0 |                             |   | 180.3                  |  |                               | 58.7    |                                              |   | 35.0        
|2000                                                |  |                          |         |                             |   |                        |  |                               |         |                                              |   |             
|Unaffiliated revenues                               |  | $                        | 421.1   |                             | $ | 2,134.7                |  | $                             | 603.8   |                                              | $ | 614.8       
|Intersegment revenues                               |  |                          | 604.6   |                             |   | 0.5                    |  |                               | 7.8     |                                              |   | 20.4        
|                                                   
|Total revenues                                      |  |                          | 1,025.7 |                             |   | 2,135.2                |  |                               | 611.6   |                                              |   | 635.2       
|Depreciation and amortization                       |  |                          | 83.6    |                             |   | 319.9                  |  |                               | 46.2    |                                              |   | 20.3        
|Equity in income of equity-method
investees (c)     |  |                          |        |                             |   | 2.4                    |  |                               |        |                                              |   |            
|Fixed charges                                       |  |                          | 18.3    |                             |   | 168.4                  |  |                               | 27.3    |                                              |   | 65.8        
|Income tax expense                                  |  |                          | 118.5   |                             |   | 72.2                   |  |                               | 21.9    |                                              |   | 17.5        
|Net income (d)                                      |  |                          | 198.6   |                             |   | 102.3                  |  |                               | 30.6    |                                              |   | 13.8        
|Segment assets                                      |  |                          | 7,295.5 |                             |   | 3,392.3                |  |                               | 1,089.9 |                                              |   | 1,491.5     
|Capital expenditures                                |  |                          | 699.0   |                             |   | 290.3                  |  |                               | 59.7    |                                              |   | 131.5       

89

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4Investments

Real Estate Projects and Investments

Real estate projects and investments consist of the following:

|At December 31,                                       |  | 2002 |      | 2001
|----------------------------------------------------- |  | ---- | ---- | ----
|
|
|Operating properties and properties under development |  | $    | 77.8 |     
|Equity interest in real estate investments            |  |      | 8.3  |     
|                                                     
|Total real estate projects and investments            |  | $    | 86.1 |     
|                                                     

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

SeeNote 2for a discussion of impairments recorded in 2002 and 2001.

Investments in Qualifying Facilities and Power Projects

Our merchant energy business holds up to a 50% ownership interest in 28 operating domestic energy projects that consist of electric generation, fuel processing, or fuel
handling facilities. Of these 28 projects, 20 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.

Investments
in qualifying facilities and domestic power projects held by our merchant energy business consist of the following:

|At December 31, |  | 2002 |       | 2001
|--------------- |  | ---- | ----- | ----
|
|
|Geothermal      |  | $    | 151.4 |     
|Coal            |  |      | 133.9 |     
|Hydroelectric   |  |      | 62.6  |     
|Biomass         |  |      | 52.6  |     
|Fuel Processing |  |      | 23.2  |     
|Solar           |  |      | 10.5  |     
|Waste to Energy |  |      |      |     
|               
|Total           |  | $    | 434.2 |     
|               

The
investment in qualifying facilities and domestic power projects were accounted for under the following methods:

|At December 31,      |  | 2002 |       | 2001
|-------------------- |  | ---- | ----- | ----
|
|
|Equity Method        |  | $    | 423.7 |     
|Cost Method          |  |      | 10.5  |     
|                    
|Total power projects |  | $    | 434.2 |     
|                    

Our
percentage voting interest in qualifying facilities and domestic power projects accounted for under the equity method ranges from 16% to 50%. Equity in earnings of these power
projects were $9.1 million in 2002, $23.1 million in 2001, and $50.2 million in 2000.

Our
power projects accounted for under the equity method include investments of $260.6 million in 2002 and $296.4 million in 2001 that sell electricity in California under
power purchase agreements called "Interim Standard Offer No. 4" agreements. We discuss these projects further inNote 11.

Our
other nonregulated businesses also held international energy projects accounted for under the equity method of $5.0 million at December 31, 2002 and $8.1 million
at December 31, 2001.

SeeNote 2for a discussion of impairments recorded in 2002 and 2001.

Orion and Financial Investments

Financial investments consist of the following:

|At December 31,                |  | 2002 |      | 2001
|------------------------------ |  | ---- | ---- | ----
|
|
|Orion                          |  | $    |     |     
|Marketable equity securities   |  |      |     |     
|Financial limited partnerships |  |      | 24.2 |     
|Leveraged leases               |  |      | 12.7 |     
|                              
|Total financial investments    |  | $    | 36.9 |     
|                              

We
discuss the sale of our investment in Orion inNote 2.

Investments Classified as Available-for-Sale

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



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

90

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

|At December 31, 2002                      |  | Amortized Cost Basis |       | Unrealized Gains |   | Unrealized Losses |  | Fair Value
|----------------------------------------- |  | -------------------- | ----- | ---------------- | - | ----------------- |  | ----------
|
|
|Marketable equity securities              |  | $                    | 642.6 |                  | $ | 18.9              |  | $         
|Corporate debt and U.S. Government agency |  |                      | 51.5  |                  |   | 1.7               |  |           
|State municipal bonds                     |  |                      | 22.0  |                  |   | 1.3               |  |           
|                                         
|Totals                                    |  | $                    | 716.1 |                  | $ | 21.9              |  | $         
|                                         

|At December 31, 2001                      |  | Amortized Cost Basis |       | Unrealized Gains |   | Unrealized Losses |  | Fair Value
|----------------------------------------- |  | -------------------- | ----- | ---------------- | - | ----------------- |  | ----------
|
|
|Marketable equity securities              |  | $                    | 816.1 |                  | $ | 270.6             |  | $         
|Corporate debt and U.S. Government agency |  |                      | 47.7  |                  |   | 1.5               |  |           
|State municipal bonds                     |  |                      | 38.4  |                  |   | 3.3               |  |           
|                                         
|Totals                                    |  | $                    | 902.2 |                  | $ | 275.4             |  | $         
|                                         

In
addition to the above securities, the nuclear decommissioning trust funds included $14.0 million at December 31, 2002 and $7.7 million at December 31, 2001
of cash and cash equivalents.

The
preceding tables include $47.4 million in 2002 of net unrealized losses and $21.0 million in 2001 of net unrealized gains associated with the nuclear decommissioning
trust funds that are reflected as a change in the nuclear decommissioning trust funds in our Consolidated Balance Sheets.

Gross
and net realized gains and losses on available-for-sale securities, excluding the gains on our sales of the Orion investment, were as follows:

|                            |  | 2002 |      | 2001 |   | 2000 |  
|--------------------------- |  | ---- | ---- | ---- | - | ---- | -
|
|
|Gross realized gains        |  | $    | 6.0  |      | $ | 47.6 |  
|Gross realized losses       |  |      | (9.5 | )    |   | (7.9 | )
|                            | 
|Net realized (losses) gains |  | $    | (3.5 | )    | $ | 39.7 |  
|                            | 

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

|At December 31, 2002                |  | Amount
|----------------------------------- |  | ------
|
|
|Less than 1 year                    |  | $     
|1-5 years                           |  |       
|5-10 years                          |  |       
|More than 10 years                  |  |       
|                                   
|Total maturities of debt securities |  | $     
|                                   

---

5Regulatory Assets (net)

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

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

|At December 31,                                          |  | 2002 |       | 2001
|-------------------------------------------------------- |  | ---- | ----- | ----
|
|
|Electric generation-related regulatory asset             |  | $    | 230.1 |     
|Income taxes recoverable through future rates (net)      |  |      | 88.8  |     
|Deferred postretirement and postemployment benefit costs |  |      | 32.3  |     
|Deferred environmental costs                             |  |      | 23.2  |     
|Deferred fuel costs (net)                                |  |      | 1.9   |     
|Workforce reduction costs                                |  |      | 28.2  |     
|Other (net)                                              |  |      | 1.2   |     
|                                                        
|Total regulatory assets (net)                            |  | $    | 405.7 |     
|                                                        

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Electric Generation-Related Regulatory Asset

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

A
portion of this regulatory asset represents the decommissioning and decontamination fund payment for federal uranium enrichment facilities that does not earn a return on the rate base
investment. These amounts were $16.3 million at December 31, 2002 and $19.2 million at December 31, 2001. Prior to the deregulation of electric generation, these costs were
recovered through the electric fuel rate mechanism, and were excluded from rate base. We will continue to amortize this amount through 2008.

Income Taxes Recoverable Through Future Rates (net)

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

Deferred Postretirement and Postemployment Benefit Costs

Deferred postretirement and postemployment benefit costs are the costs we recorded under SFAS No. 106 (for postretirement benefits) and No. 112 (for
postemployment benefits) in excess of the costs we included in the rates we charge our customers. We began amortizing these costs over a 15-year period in 1998. We discuss these costs
further inNote 6.

Deferred Environmental Costs

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

Deferred Fuel Costs

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

In
December 2002, a Hearing Examiner from the Maryland PSC issued a proposed order related to our annual gas adjustment clause review proceeding that will allow us to recover
$1.7 million of a previously established regulatory asset of $9.4 million for certain credits that were over-refunded to customers through our market-based rates. BGE
reserved the remaining difference of $7.7 million as disallowed fuel costs. However, we appealed the proposed order. As of the date of this report, the Maryland PSC has not acted on BGE's
appeal.

Our
gas deferred fuel costs were $1.9 million at December 31, 2002 and $33.5 million at December 31, 2001.

We
exclude gas deferred fuel costs from rate base because their existence is relatively short-lived. These costs are recovered in the following year through the market-based rate
mechanism.

Workforce Reduction Costs

The portions of the costs associated with the VSERP and workforce reduction programs we announced that relate to BGE's gas business are deferred as regulatory assets in
accordance with the Maryland PSC's orders in prior rate cases. These costs are amortized over 5-year periods. SeeNote 2and Note 6.

92

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6Pension, Postretirement, Other Postemployment, and Employee Savings Plan Benefits

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

Pension Benefits

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

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

We
fund the plans by contributing at least the minimum amount required under Internal Revenue Service regulations. We calculate the amount of funding using an actuarial method called the
projected unit credit cost method. The assets in all of the plans at December 31, 2002 were mostly marketable equity and fixed income securities.

Postretirement Benefits

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

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

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

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



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



Beginning
in 1998, the Maryland PSC authorized us to:



Effective
in 2002, we amended our postretirement medical plans for all affiliates other than Nine Mile Point. Our contributions for retiree medical coverage for future retirees that were
under the age of 55 on January 1, 2002 are capped at the 2002 level. We also amended our plans to increase the Medicare eligible retirees' share of medical costs.

VSERP

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

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

93

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

The
age 50 to 54 program allowed employees to make their elections beginning in 2002. The cost of that program was approximately $52.9 million ($43.0 million in pension
termination costs, $8.5 million in postretirement benefit costs, and $1.4 million in education and outplacement assistance costs). Of this amount, BGE recorded approximately
$13.4 million on its balance sheet as a regulatory asset of its gas business. We incurred approximately $0.7 million of postretirement benefit costs related to additional workforce
reduction initiatives in 2002.

In
connection with the retirement of a significant number of the participants in the nonqualified pension plans we recognized a settlement loss of approximately $10.5 million and
a curtailment loss of approximately $5.8 million for those plans in accordance with SFAS No. 88 in 2001. We recorded additional settlement charges of $29.6 million related to our
qualified and nonqualified pension plans in 2002 as a result of retirees electing to take their pension benefit in the form of a lump-sum payment.

At
December 31, 2002, our pension obligations were greater than the fair value of our plan assets for our qualified and our nonqualified pension plans as follows:

|                               |  | Qualified Plans |      |  |   |      
|------------------------------ |  | --------------- | ---- |  | - | -----
|
|
|
|Accumulated benefit obligation |  | $               | 85.7 |  | $ | 981.6
|Fair value of assets           |  |                 | 57.8 |  |   | 709.9
|                              
|Unfunded obligation            |  | $               | 27.9 |  | $ | 271.7
|                              

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

In
2002, we recorded an additional minimum pension liability of $189.5 million as a result of the decreases in the fair value of plan assets due to continued declines in the
equity markets. We recorded $5.8 million of this adjustment as a reduction to an intangible asset. We included the remaining $195.3 million, or $118.1 million
after-tax, of this adjustment in "Accumulated other comprehensive income."

The
cost of the voluntary retirement programs and the settlement and curtailment losses are not included in the tables of net periodic pension and postretirement benefit costs for the
respective years.

Obligations, Assets, and Funded Status

We show the change in the benefit obligations, plan assets, and funded status of the pension and postretirement benefit plans in the following tables.

|                                  |  | Pension
Benefits |         | Postretirement
Benefits |  
|--------------------------------- |  | ---------------- | ------- | ----------------------- | -
|
|
|
|Change in benefit obligation      |  |                  |         |                         |  
|Benefit obligation at January 1   |  | $                | 1,259.2 |                         | $
|Service cost                      |  |                  | 29.6    |                         |  
|Interest cost                     |  |                  | 82.2    |                         |  
|Plan participants' contributions  |  |                  |        |                         |  
|Actuarial loss                    |  |                  | 78.9    |                         |  
|Plan amendments                   |  |                  |        |                         |  
|VSERP charge                      |  |                  | 43.0    |                         |  
|Curtailment                       |  |                  |        |                         |  
|Settlement                        |  |                  | (37.9   | )                       |  
|Nine Mile Point acquisition       |  |                  |        |                         |  
|Benefits paid                     |  |                  | (207.5  | )                       |  
|                                  | 
|Benefit obligation at December 31 |  | $                | 1,247.5 |                         | $
|                                  | 

94

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|                                         |  | Pension
Benefits |        | Postretirement
Benefits |  
|---------------------------------------- |  | ---------------- | ------ | ----------------------- | -
|
|
|
|Change in plan assets                    |  |                  |        |                         |  
|Fair value of plan assets at January 1   |  | $                | 912.2  |                         | $
|Actual return on plan assets             |  |                  | (89.4  | )                       |  
|Employer contribution                    |  |                  | 152.4  |                         |  
|Plan participants' contributions         |  |                  |       |                         |  
|Benefits paid                            |  |                  | (207.5 | )                       |  
|                                         | 
|Fair value of plan assets at December 31 |  | $                | 767.7  |                         | $
|                                         | 

|                                   |  | Pension
Benefits |        | Postretirement
Benefits |  
|---------------------------------- |  | ---------------- | ------ | ----------------------- | -
|
|
|
|Funded Status                      |  |                  |        |                         |  
|Funded Status at December 31       |  | $                | (479.8 | )                       | $
|Unrecognized net actuarial loss    |  |                  | 417.8  |                         |  
|Unrecognized prior service cost    |  |                  | 49.9   |                         |  
|Unrecognized transition obligation |  |                  |       |                         |  
|Pension liability adjustment       |  |                  | (322.5 | )                       |  
|                                   | 
|Accrued benefit cost               |  | $                | (334.6 | )                       | $
|                                   | 

Net Periodic Benefit Cost

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

|Year Ended December 31,                         |  | 2002 |       | 2001 |   | 2000  |  
|----------------------------------------------- |  | ---- | ----- | ---- | - | ----- | -
|
|
|Components of net periodic pension benefit cost |  |      |       |      |   |       |  
|Service cost                                    |  | $    | 29.6  |      | $ | 25.8  |  
|Interest cost                                   |  |      | 82.2  |      |   | 76.1  |  
|Expected return on plan assets                  |  |      | (91.0 | )    |   | (87.5 | )
|Amortization of transition obligation           |  |      |      |      |   | (0.2  | )
|Amortization of prior service cost              |  |      | 6.7   |      |   | 6.5   |  
|Recognized net actuarial loss                   |  |      | 1.3   |      |   | 2.8   |  
|Amount capitalized as construction cost         |  |      | (2.9  | )    |   | (2.5  | )
|                                                | 
|Net periodic pension benefit cost               |  | $    | 25.9  |      | $ | 21.0  |  
|                                                | 

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

|Year Ended December 31,                                |  | 2002 |      | 2001 |   | 2000  |  
|------------------------------------------------------ |  | ---- | ---- | ---- | - | ----- | -
|
|
|Components of net periodic postretirement benefit cost |  |      |      |      |   |       |  
|Service cost                                           |  | $    | 5.0  |      | $ | 8.4   |  
|Interest cost                                          |  |      | 26.7 |      |   | 29.2  |  
|Amortization of transition obligation                  |  |      | 2.1  |      |   | 7.9   |  
|Recognized net actuarial loss                          |  |      | 6.4  |      |   | 3.3   |  
|Amortization of unrecognized prior service cost        |  |      | (3.5 | )    |   |      |  
|Amount capitalized as construction cost                |  |      | (9.1 | )    |   | (14.5 | )
|                                                       | 
|Net periodic postretirement benefit cost               |  | $    | 27.6 |      | $ | 34.3  |  
|                                                       | 

Assumptions

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

|                               |  | Pension
Benefits |   | Postretirement
Benefits |   |      |  
|------------------------------ |  | ---------------- | - | ----------------------- | - | ---- | -
|
|
|
|Discount rate                  |  | 6.75             | % | 7.25                    | % | 6.75 | %
|Expected return on plan assets |  | 9.00             |   | 9.00                    |   | N/A  |  
|Rate of compensation increase  |  | 4.00             |   | 4.00                    |   | 4.00 |  

We
assumed the health care inflation rates to be:



After
2003, we assumed inflation rates will decrease to 8.0% in 2004, 6.0% in 2005, 5.5% from 2006 through 2008 and 5.0% annually after 2008.

A
one-percent increase in the health care inflation rate from the assumed rates would increase the accumulated postretirement benefit obligation by approximately
$34.3 million as of December 31, 2002 and would increase the combined service and interest costs of the postretirement benefit cost by approximately $2.6 million annually.

A
one-percent decrease in the health care inflation rate from the assumed rates would decrease the accumulated postretirement benefit obligation by approximately
$29.0 million as of December 31, 2002 and would decrease the combined service and interest costs of the postretirement benefit cost by approximately $2.2 million annually.

95

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Other Postemployment Benefits

We provide the following postemployment benefits:



The
liability for these benefits totaled $49.7 million as of December 31, 2002 and $48.7 million as of December 31, 2001.

Effective
December 31, 1993, we adopted SFAS No. 112,Employers' Accounting for Postemployment Benefits. We deferred, as a
regulatory asset (seeNote 5), the postemployment benefit liability attributable to our regulated utility business as of December 31,
1993, consistent with the Maryland PSC's orders for postretirement benefits (described earlier in this Note).

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

We
assumed the discount rate for other postemployment benefits to be 5.75% in 2002 and 5.0% in 2001.

Employee Savings Plan Benefits

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



---

7Short-Term Borrowings

Our
short-term borrowings may include bank loans, commercial paper, and bank lines of credit. Short-term borrowings mature within one year from the date of issuance. We pay
commitment fees to banks for providing us lines of credit. When we borrow under the lines of credit, we pay market interest rates.

Constellation Energy

Constellation Energy had committed bank lines of credit under three credit facilities of $1.5 billion at December 31, 2002 for short-term financial
needs as follows:



We
use these facilities to allow issuance of commercial paper and letters of credit primarily for our merchant energy business. These facilities can issue letters of credit up to
approximately $1.1 billion. Letters of credit issued under all of our facilities totaled $338.7 million at December 31, 2002 and $245.8 million at December 31, 2001.
Constellation Energy had no commercial paper outstanding at December 31, 2002 and $954.9 million at December 31, 2001.

The
weighted-average effective interest rates for Constellation Energy's commercial paper were 2.37% for the year ended December 31, 2002 and 3.73% for 2001.

BGE

BGE had no commercial paper outstanding at December 31, 2002 and 2001.

BGE
maintains $200.0 million in annual committed credit facilities, expiring May through November of 2003, in order to allow commercial paper to be issued. At December 31,
2002, BGE had $200.0 million in unused credit facilities.

Other Nonregulated Businesses

Our other nonregulated businesses had short-term borrowings outstanding of $10.5 million at December 31, 2002 and $20.1 million at
December 31, 2001. The weighted-average effective interest rates for our other nonregulated businesses' short-term borrowings were 3.61% at December 31, 2002 and 4.20% for
2001.

96

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8Long-Term Debt and Preference Stock

Long-term Debt

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

Constellation Energy

Constellation Energy issued the following fixed rate notes during 2002:

|                                              |  | Principal |         | Date
Issued |       | Maturity
and
Repayment
Date |      | Net
Proceeds
|--------------------------------------------- |  | --------- | ------- | ----------- | ----- | --------------------------- | ---- | ------------
|
|
|6.35% Notes (interest payable semi-annually)  |  | $         | 600.0   |             | 3/02  |                             | 4/07 |             
|7.00% Notes (interest payable semi-annually)  |  |           | 600.0   |             | 3/02  |                             | 4/12 |             
|7.60% Notes (interest payable semi-annually)  |  |           | 600.0   |             | 3/02  |                             | 4/32 |             
|6.125% Notes (interest payable semi-annually) |  |           | 500.0   |             | 8/02  |                             | 9/09 |             
|7.00% Notes (interest payable semi-annually)  |  |           | 100.0   |             | 12/02 |                             | 4/12 |             
|7.60% Notes (interest payable semi-annually)  |  |           | 100.0   |             | 12/02 |                             | 4/32 |             
|                                             
|Total                                         |  | $         | 2,500.0 |             |       |                             |      |             
|                                             

We used a portion of the net proceeds to repay short-term borrowings, to prepay the sellers' note of $388.1 million originally
issued for the acquisition of Nine Mile Point Nuclear Station (Nine Mile Point), and to fund other acquisitions.

BGE

BGE's First Refunding Mortgage Bonds

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

BGE
is required to make an annual sinking fund payment each August 1 to the mortgage trustee. The amount of the payment is equal to 1% of the highest principal amount of bonds
outstanding during the preceding 12 months. The trustee uses these funds to retire bonds from any series through repurchases or calls for early redemption. However, the trustee cannot call the
following bonds for early redemption:

| |  61/2% Series, due 2003 |  |  71/2% Series, due 2007
| | ------------------------ |  | ------------------------
| |  61/8% Series, due 2003 |  |  65/8% Series, due 2008
| |  51/2% Series, due 2004 |  |                         

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

On
August 28, 2002, BGE called $11.8 million principal amount of its 71/2% Series, due April 15, 2023 First Refunding Mortgage Bonds in connection
with its annual sinking fund. Bonds called were redeemed at the price of 100% of principal, plus accrued interest from April 15, 2002 to August 28, 2002.

BGE's Other Long-Term Debt

On July 1, 2000, BGE transferred $278.0 million of tax-exempt debt to our merchant energy business related to the transferred assets. At
December 31, 2002, BGE remains contingently liable for the $269.8 million outstanding balance of this debt.

On
December 20, 2000, BGE issued $173.0 million of 6.75% Remarketable and Redeemable Securities (ROARS) due December 15, 2012. On December 15, 2002, BGE
redeemed all the outstanding ROARS at 100% of the principal amount.

We
show the weighted-average interest rates and maturity dates for BGE's fixed-rate medium-term notes outstanding at December 31, 2002 in the following
table.

|Series |  | Weighted-Average
Interest Rate |   | Maturity
Dates
|------ |  | ------------------------------ | - | --------------
|
|B      |  | 8.62                           | % | 2006          
|C      |  | 7.97                           |   | 2003          
|D      |  | 6.67                           |   | 2004-2006     
|E      |  | 6.66                           |   | 2006-2012     
|G      |  | 6.08                           |   | 2008          

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

|Series E Notes  |  | Principal |      | Put Option Dates
|--------------- |  | --------- | ---- | ----------------
|
|
|6.75%, due 2012 |  | $         | 60.0 |                 
|6.75%, due 2012 |  | $         | 25.0 |                 
|6.73%, due 2012 |  | $         | 25.0 |                 

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BGE Obligated Mandatorily Redeemable Trust Preferred Securities

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

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

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

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

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

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

Other Nonregulated Businesses

In November 2002, our other nonregulated businesses entered into a long-term bank facility of $51.7 million in principal with an interest rate of
3.25% fixed rate plus 3 months Eurodollar rate (interest payable quarterly), due December 2008 for net proceeds of $50.4 million.

Revolving Credit Agreement

ComfortLink had a $50 million unsecured revolving credit agreement that matured September 26, 2002. Under this agreement, ComfortLink had no amount outstanding at
December 31, 2002 and $46.0 million outstanding at December 31, 2001.

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

Debt Compliance and Covenants

The credit facilities of Constellation Energy and BGE have limited material adverse change clauses that only consider a material change in financial condition and are not
directly affected by decreases in credit ratings. If these clauses are violated, the lending institutions can decline making new advances or issuing new letters of credit, but cannot accelerate
existing amounts outstanding. The 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, 2002, the debt to capitalization ratios as defined in the credit agreements were no greater than 57%.

A
BGE credit facility of $50.0 million that expires in August 2003 requires BGE to maintain a ratio of debt to capitalization equal to or less than 70%. At
December 31, 2002, the debt to capitalization ratio for BGE as defined in the credit agreement was 54%. At December 31, 2002, no amounts were outstanding under the BGE facility.

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.

Maturities of Long-Term Debt

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

|Year                                      |  | Constellation Energy |         | Nonregulated Business |   | BGE  
|----------------------------------------- |  | -------------------- | ------- | --------------------- | - | -----
|
|
|2003                                      |  | $                    |        |                       | $ | 5.5  
|2004                                      |  |                      |        |                       |   | 7.5  
|2005                                      |  |                      | 300.0   |                       |   | 8.1  
|2006                                      |  |                      |        |                       |   | 9.6  
|2007                                      |  |                      | 600.0   |                       |   | 10.5 
|Thereafter                                |  |                      | 1,900.0 |                       |   | 308.6
|                                         
|Total long-term debt at December 31, 2002 |  | $                    | 2,800.0 |                       | $ | 349.8
|                                         

98

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At December 31, 2002, we had long-term loans totaling $394.3 million that mature after 2002 which contain certain put
options under which lenders could potentially require us to repay the debt prior to maturity. At December 31, 2002, $136.5 million is classified as current portion of
long-term debt as a result of these provisions.

Weighted-Average Interest Rates for Variable Rate Debt

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

|At December 31,                                          |                                                | 2002 |      | 2001 |     
|-------------------------------------------------------- | ---------------------------------------------- | ---- | ---- | ---- | ----
|
|Nonregulated Businesses (including Constellation Energy) |                                                |      |      |      |     
|                                                         | Floating rate notes                            |      |     | %    | 4.95
|                                                         | Loans under credit agreements                  |      | 4.42 |      | 4.60
|                                                         | Mortgage and construction loans                |      |     |      | 4.39
|                                                         | Tax-exempt debt transferred from BGE           |      | 1.97 |      | 3.12
|                                                         | Other tax-exempt debt                          |      | 1.49 |      | 1.75
|BGE                                                      |                                                |      |      |      |     
|                                                         | Remarketed floating rate series mortgage bonds |      | 1.91 | %    | 4.49
|                                                         | Floating rate reset notes                      |      |     |      | 4.14

Preference Stock

Each series of BGE preference stock has no voting power, except for the following:



99

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|Year Ended December 31, |                                                    | 2002    |   | 2001  |       | 2000 |      
|----------------------- | -------------------------------------------------- | ------- | - | ----- | ----- | ---- | -----
|
|
|Income Taxes            |                                                    |         |   |       |       |      |      
|                        | Current                                            |         |   |       |       |      |      
|                        |                                                    | Federal |   | $     | 145.0 |      | $    
|                        |                                                    | State   |   |       | 24.2  |      |      
|                        |                                                   
|                        | Current taxes charged to expense                   |         |   | 169.2 |       |      | 72.5 
|                        | Deferred                                           |         |   |       |       |      |      
|                        |                                                    | Federal |   |       | 131.2 |      |      
|                        |                                                    | State   |   |       | 17.1  |      |      
|                        |                                                   
|                        | Deferred taxes charged to expense                  |         |   | 148.3 |       |      | (26.5
|                        | Investment tax credit adjustments                  |         |   | (7.9  | )     |      | (8.1 
|                        |                                                   
|                        | Income taxes per Consolidated Statements of Income |         | $ | 309.6 |       | $    | 37.9 
|                        |                                                   

Total
income taxes are different from the amount that would be computed by applying the statutory Federal income tax rate of 35% to book income before income taxes as
follows:

|Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes |                                                                       |                                                 |                                                                 |       |       |       |       |      |       |      
|--------------------------------------------------------------------------------------- | --------------------------------------------------------------------- | ----------------------------------------------- | --------------------------------------------------------------- | ----- | ----- | ----- | ----- | ---- | ----- | -----
|                                                                                        | Income before income taxes (excluding BGE preference stock dividends) |                                                 | $                                                               | 848.4 |       | $     | 133.5 |      | $     | 588.6
|                                                                                        |                                                                       | Statutory federal income tax rate               |                                                                 |       | 35    | %     |       | 35   | %     |      
|                                                                                        |                                                                      
|                                                                                        |                                                                       | Income taxes computed at statutory federal rate |                                                                 |       | 296.9 |       |       | 46.7 |       |      
|                                                                                        |                                                                       | Increases (decreases) in income taxes due to    |                                                                 |       |       |       |       |      |       |      
|                                                                                        |                                                                       |                                                 | Depreciation differences not normalized on regulated activities |       |       | 4.8   |       |      | 5.6   |      
|                                                                                        |                                                                       |                                                 | Amortization of deferred investment tax credits                 |       |       | (7.9  | )     |      | (8.1  | )    
|                                                                                        |                                                                       |                                                 | Synthetic fuel tax credits flowed through to income             |       |       | (20.7 | )     |      | (13.4 | )    
|                                                                                        |                                                                       |                                                 | State income taxes, net of federal income tax benefit           |       |       | 31.4  |       |      | 13.5  |      
|                                                                                        |                                                                       |                                                 | Other                                                           |       |       | 5.1   |       |      | (6.4  | )    
|                                                                                        |                                                                      
|                                                                                        |                                                                       | Total income taxes                              |                                                                 | $     | 309.6 |       | $     | 37.9 |       | $    
|                                                                                        |                                                                      
|                                                                                        | Effective income tax rate                                             |                                                 |                                                                 | 36.5  | %     |       | 28.4  | %    |       | 39.1 

The major components of our net deferred income tax liability are as follows:

|At December 31,       |                             | 2002                                                |   | 2001   
|--------------------- | --------------------------- | --------------------------------------------------- | - | -------
|
|
|Deferred Income Taxes |                             |                                                     |   |        
|                      | Deferred tax liabilities    |                                                     |   |        
|                      |                             | Net property, plant and equipment                   |   | $      
|                      |                             | Regulatory assets, net                              |   |        
|                      |                             | Power marketing and risk management activities, net |   |        
|                      |                             | Financial investments and hedging instruments       |   |        
|                      |                             | Other                                               |   |        
|                     
|                      |                             | Total deferred tax liabilities                      |   |        
|                      | Deferred tax assets         |                                                     |   |        
|                      |                             | Accrued pension and postemployment benefit costs    |   |        
|                      |                             | Deferred investment tax credits                     |   |        
|                      |                             | Nuclear decommissioning liability                   |   |        
|                      |                             | Reduction of investments                            |   |        
|                      |                             | Other                                               |   |        
|                     
|                      |                             | Total deferred tax assets                           |   |        
|                     
|                      | Deferred tax liability, net |                                                     | $ | 1,330.7
|                     

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

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10Leases

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

Outgoing Lease Payments

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

Lease
expense was:



At
December 31, 2002, we owed future minimum payments for long-term, noncancelable, operating leases as follows:

|Year                                |  |  
|----------------------------------- |  | -
|
|
|2003                                |  | $
|2004                                |  |  
|2005                                |  |  
|2006                                |  |  
|2007                                |  |  
|Thereafter                          |  |  
|                                   
|Total future minimum lease payments |  | $
|                                   

The above table includes the operating lease payments for the High Desert project in California through 2006. The project is scheduled for
completion in mid-2003.

The
High Desert project uses an off-balance sheet financing structure through a special-purpose entity (SPE) that qualifies as an operating lease. Our wholly owned
subsidiary, High Desert Power Project LLC, is supervising the construction of, and leasing, the High Desert project from High Desert Power Trust, an independent SPE created to own and lease the
project to our subsidiary. Neither Constellation Energy nor any affiliate owns any equity or other interest in High Desert Power Trust, which is owned by a consortium of banks and other financial
institutions. We provide a guaranty of High Desert Power Project LLC's obligations to the Trust.

Accounting
rules presently in effect for SPEs formed prior to February 2003, require that an SPE lessor must have sufficient independent equity at risk in order for us not to
consolidate it. High Desert Power Trust maintains such a level of equity at risk, since the owners of the Trust maintain a minimum of 3% real equity at risk. In January 2003, the FASB issued
Interpretation No. 46,Consolidation of Variable Interest Entities,which will require us to consolidate the Trust based on the current lease
structure beginning July 1, 2003. We discuss this further inNote 1.

Under
the terms of the lease, we are required to make payments that represent all or a portion of the lease balance if construction is terminated prior to completion or we default under
the lease.

In
addition, we may be required to either post cash collateral equal to the outstanding lease balance or we may elect to purchase the property for the outstanding lease balance. At any
time during the term of the lease we have the right to pay off the lease and acquire the asset from the lessor. At December 31, 2002, the outstanding lease balance plus other committed expenses
was approximately $585 million.

The
lease with the Trust contains several events of default that are commonly found in financings of this type, including failure to make all payments when due, failure to comply with
all covenants, violation of material representations and warranties and change of control. In addition, several events of default are applicable to us as guarantor, including defaults in other
material financing agreements and failure to own 100% of BGE's common stock.

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



If
the lessor sells the property, we guarantee the payment of any difference between the sale proceeds and the lease balance at the time of sale up to a maximum amount of approximately
83% of such lease balance. The lease balance at the end of the term is currently estimated to be $600 million, which represents the estimated cost of the project; however, this may vary based
on the ultimate cost of construction and interest incurred during the construction period.

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11Commitments, Guarantees, and Contingencies

Commitments

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



Our
merchant energy business has a long-term contract for the purchase of electric generating capacity and energy that expires in 2013. Portions of this contract became
uneconomical upon the deregulation of electric generation. Therefore, we recorded a charge and accrued a corresponding liability based on the net present value of the excess of estimated contract
costs over the market-based revenues to recover these costs over the remaining term of the contract. At December 31, 2002, the accrued portion of this contract was $9.2 million.

Our
merchant energy business enters into various long-term contracts for the procurement and delivery of fuels to supply our generating plant requirements. In most cases, our
contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. These contracts expire in various years between 2003 and 2013. In addition, our merchant
energy business enters into long-term contracts for the capacity and transmission rights for the delivery of energy to meet our physical obligations to our customers. These contracts
expire in various years between 2003 and 2013.

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

At
December 31, 2002, we estimate the future obligations of our merchant energy business in the following table:

|                              |  | 2003 |       | 2004 |   | 2005  |  | 2006 |       | 2007 |   | Thereafter |  | Total
|----------------------------- |  | ---- | ----- | ---- | - | ----- |  | ---- | ----- | ---- | - | ---------- |  | -----
|
|
|Purchased capacity and energy |  | $    | 182.8 |      | $ | 106.5 |  | $    | 54.2  |      | $ | 33.6       |  | $    
|Fuel and transportation       |  |      | 618.5 |      |   | 243.8 |  |      | 70.4  |      |   | 117.6      |  |      
|Capital and loans             |  |      | 32.7  |      |   | 0.5   |  |      |      |      |   |           |  |      
|                             
|Total future obligations      |  | $    | 834.0 |      | $ | 350.8 |  | $    | 124.6 |      | $ | 151.2      |  | $    
|                             

Our regulated gas business entered into various long-term contracts that expire from 2004 to 2012 for the procurement, transportation, and storage of
gas. These contracts are recoverable under BGE's gas cost adjustment clause discussed inNote 1.

BGE
Home Products & Services has gas purchase commitments of $8.4 million in 2003 and $2.7 million in 2004 related to its gas program.

Long-Term Power Sales Contracts

We entered into long-term power sales contracts in connection with our load-serving activities. We also entered into long-term power sales
contracts associated with certain of our power plants. Our load-serving power sales contracts extend for terms through 2009 and provide for the sale of full requirements energy to
electricity distribution utilities and certain retail customers. Our power sales contracts associated with our power plants extend for terms into 2011 and provide for the sale of all or a portion of
the actual output of certain of our power plants. All long-term contracts were executed at pricing that approximated market rates, including profit margin, at the time of execution.

Sale of Receivables

BGE Home Products & Services has an agreement to sell on an ongoing basis an undivided interest in a designated pool of customer receivables. Under the agreement, BGE
Home Products & Services can sell up to a total of $50 million. Under the terms of the agreement, the buyer of the receivables has limited recourse against BGE Home Products &
Services. BGE Home Products & Services recorded reserves for credit losses. At December 31, 2002, BGE Home Products & Services sold $47.7 million of receivables under the
agreement.

Guarantees

The terms of our guarantees are as follows:

|                   |                  | Payments/Expiration |         |        
|------------------ | ---------------- | ------------------- | ------- | -------
|
|
|Competitive Supply |                  | $                   | 1,758.8 |        
|Other              |                  |                     | 16.5    |        
|                  
|                   | Total Guarantees |                     | $       | 1,775.3
|                  

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At December 31, 2002, Constellation Energy had a total of $3,188.3 million guarantees outstanding related to loans, credit
facilities, and contractual performance of certain of its subsidiaries as described below. These guarantees do not represent our incremental obligations and we do not expect to fund the full amount
under these guarantees.



The
total fair value of the obligations for our guarantees recorded in our Consolidated Balance Sheets was $765.3 million and not the $3.2 billion of total guarantees. We
assess the risk of loss from these guarantees to be minimal.

Environmental Matters

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



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

We
discuss the significant matters below.

Clean Air Act

The Clean Air Act affects both existing generating facilities and new projects. The Clean Air Act and many state laws require significant reductions in SO2 (sulfur
dioxide) and NOx (nitrogen oxide) emissions that result from burning fossil fuels. The Clean Air Act also contains other provisions that could materially affect some of our projects.
Various provisions may require permits, inspections, or installation of additional pollution control technology 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. Among
other things, the EPA's rule establishes an ozone season, which runs from May through September, and a NOX emission budget for each state, including Maryland and Pennsylvania. The EPA rule
requires states to implement controls sufficient to meet their NOX budget by May 30, 2004. Coal-fired power plants are a principal target of NOX reductions
under this initiative.

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 to meet Maryland regulations issued pursuant to EPA's rule. The owners of the Keystone plant in Pennsylvania are installing emissions
reduction equipment by July 2003 to meet Pennsylvania regulations issued pursuant to EPA's rule. We estimate our costs for the equipment needed at this plant will be approximately
$35 million. Through December 31, 2002, we have spent approximately $26 million.

103

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

The
EPA and several states have filed suits against a number of coal-fired power plants in Mid-Western and Southern states alleging violations of the
deterioration prevention and non-attainment provisions of the Clean Air Act's new source review requirements. In 2000, and again in 2002, using its broad investigatory powers, the EPA
requested information relating to modifications made to our Brandon Shores, Crane, and Wagner plants in Baltimore, Maryland. The EPA also sent similar, but narrower, information requests to two of our
newer Pennsylvania waste-coal burning plants. This information is to determine compliance with the Clean Air Act and state implementation plan requirements, including potential application
of federal New Source Performance Standards. We have responded to the EPA and as of the date of this report the EPA has taken no further action.

In
general, such standards can require the installation of additional air pollution control equipment upon the major modification of an existing plant. Although there have not been any
new source review-related suits filed against our facilities, there can be no assurance that any of them will not be the target of an action in the future. Based on the levels of emissions control
that the EPA and states are seeking in these new source review enforcement actions, we believe that material additional costs and penalties could be incurred, and planned capital expenditures could be
accelerated, if the EPA was successful in any future actions regarding our facilities.

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

Future
initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. The related Kyoto Protocol was signed by the United States but has
since been rejected by the President, who instead has asked for an 18% decrease in carbon intensity on a voluntary basis. Future initiatives on this issue and the ultimate effects of the Kyoto
Protocol and the President's initiatives on us are unknown at the date of this report. 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 stormwater discharges.

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

Waste Disposal

The EPA and several state agencies have notified us that we are considered a potentially responsible party with respect to the cleanup of certain environmentally contaminated
sites owned and operated by others. We cannot estimate the cleanup costs for all of these sites.

However,
based on a Record of Decision issued by the EPA in 1997, we can estimate that BGE's current 15.47% share of the reasonably possible cleanup costs at one of these sites, Metal
Bank of America, a metal reclaimer in Philadelphia, could be as much as $1.3 million higher than amounts we believe are probable and have recorded as a liability in our Consolidated Balance
Sheets. There has been no significant activity with respect to this site since the EPA's Record of Decision in 1997.

In
late December 1996, BGE signed a consent order with the Maryland Department of the Environment that required it to implement remedial action plans for contamination at and
around the Spring Gardens site, located in Baltimore, Maryland. The Spring Gardens site was once used to manufacture gas from coal and oil. BGE submitted the required remedial action plans and they
were 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 on its Consolidated Balance Sheets and deferred these costs, net of accumulated amortization and amounts it recovered from insurance companies, as a regulatory
asset. Because of the results of studies at this site, it is reasonably possible that additional costs could exceed the amount BGE recognized by approximately $14 million. Through
December 31, 2002, BGE spent approximately $39 million for remediation at this site. BGE also investigated other small sites where gas was manufactured in the past. We do not expect the
cleanup costs of the remaining smaller sites to have a material effect on our financial results.

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Litigation

In the normal course of business, we are involved in various legal proceedings. We discuss the significant matters below.

California

Baldwin Associates, Inc. v. Gray Davis, Governor of California and 22 other defendants (including Constellation Power Development, Inc., a
subsidiary of Constellation Power, Inc.)This class action lawsuit was filed on October 5, 2001 in the Superior Court, County of San Francisco. The
action seeks damages of $43 billion, recession and reformation of approximately 38 long-term power purchase contracts, and an injunction against improper spending by the state of
California.

Constellation
Power Development, Inc. is named as a defendant but does not have a power purchase agreement with the State of California. However, our High Desert Power Project
does have a power purchase agreement with the California Department of Water Resources. In 2002, the court issued an order to the plaintiff asking that he show cause why he had not yet served the
defendants. In April 2002, a second show cause order was issued. After several postponements, a hearing is now scheduled in March 2003 on that order.

NewEnergy

Constellation NewEnergy, Inc. v. PowerWeb Technology, Inc.Prior to our acquisition, NewEnergy filed a
complaint on May 9, 2002 in the U.S. District Court of Eastern Pennsylvania seeking approximately $100,000 in direct damages relating to a contract previously entered into with PowerWeb.
PowerWeb Technology has counter-claimed seeking $100 million in damages against NewEnergy alleging a breach of a non-disclosure agreement by misappropriation of trade secrets. To
date, discovery has just begun. We cannot predict the timing, or outcome, of the action or its possible effect on our financial results. However, based on the information available to Constellation
Energy at this time, we believe NewEnergy has meritorious defenses to the PowerWeb Technology counterclaim.

Mercury Poisoning

Beginning in September 2002, BGE, Constellation Energy, and several other defendants have been involved in numerous actions alleging mercury poisoning from several
sources, including coal plants formerly owned by BGE. The plants are now owned by a subsidiary of Constellation Energy. In addition to BGE and Constellation Energy, approximately 11 other defendants,
consisting of pharmaceutical companies, manufacturers of vaccines and manufacturers of Thimerosal have been sued. Approximately 50 cases have been filed to date, with each case seeking
$90 million in damages from the group of defendants. The claims were filed in the Circuit Court for Baltimore City, Maryland beginning in September 2002. The plaintiffs have filed
motions to remand the cases back to the Baltimore City Circuit Court. At this time no discovery has occurred. We believe that we have meritorious defenses and intend to defend the action vigorously.
However, we cannot predict the timing, or outcome, of these cases, or their possible effect on our, or BGE's, financial results.

Employment Discrimination

Miller, et. al v. Baltimore Gas and Electric Company, et al.This action was filed on September 20, 2000 in
the U.S. District Court for the District of Maryland. Besides BGE, Constellation Energy Group, Constellation Nuclear, and Calvert Cliffs Nuclear Power Plant are also named defendants. The action seeks
class certification for approximately 150 past and present employees and alleges racial discrimination at Calvert Cliffs Nuclear Power Plant. The amount of damages is unspecified, however the
plaintiffs seek back and front pay, along with compensatory and punitive damages. The Court scheduled a briefing process for the motion to certify the case as a class action suit. The briefing process
is scheduled to end in July 2003. We do not believe class certification is appropriate and we further believe that we have meritorious defenses to the underlying claims and intend to defend the
action vigorously. However, we cannot predict the timing, or outcome, of the action or its possible effect on our, or BGE's, financial results.

Asbestos

Since 1993, BGE has been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that BGE knew of and exposed
individuals to an asbestos hazard. The actions relate to two types of claims.

The
first type is direct claims by individuals exposed to asbestos. BGE is involved in these claims with approximately 70 other defendants. Approximately 600 individuals that were never
employees of BGE each claim $6 million in damages ($2 million compensatory and $4 million punitive). These claims were filed in the Circuit Court for Baltimore City, Maryland in
the summer of 1993. BGE does not know the specific facts necessary to estimate its potential liability for these claims. The specific facts BGE does not know include:



To
date, 67 of these cases were settled for amounts that were not significant. Approximately 300 cases are scheduled for trial in 2003.

The
second type is claims by one manufacturerPittsburgh Corning Corp. (PCC)against BGE and approximately eight others, as third-party defendants. On
April 17, 2000, PCC declared bankruptcy.

These
claims relate to approximately 1,500 individual plaintiffs and were filed in the Circuit Court for Baltimore City, Maryland in the fall of 1993. To date, about 375 cases have been
resolved, all without any payment by BGE. BGE does not know the specific facts necessary to estimate its potential liability for these claims. The specific facts we do not know include:



105

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Until
the relevant facts for both types of claims are determined, we are unable to estimate what our, or BGE's, liability might be. Although insurance and hold harmless agreements from
contractors who employed the plaintiffs may cover a portion of any awards in the actions, the potential effect on our, or BGE's, financial results could be material.

Other

McCray, et. al.v. Baltimore Gas and Electric CompanyOn June 10, 2002, a suit was filed in the Circuit Court
of Baltimore City, Maryland seeking a total of $585 million in compensatory and punitive damages from BGE as a result of a fire in a home that caused five fatalities. Electricity to the home
was shut off. BGE believes it has meritorious defenses and intends to defend the action vigorously. However, we cannot predict the timing, or outcome, of the action or its possible effect on our, or
BGE's, financial results.

Storage of Spent Nuclear Fuel

On February 14, 2002, the Secretary of Energy submitted to the President a recommendation for approval of the Yucca Mountain site for the development of a nuclear waste
repository for the disposal of spent nuclear fuel and high level nuclear waste from the nation's defense activities. In July 2002, the President signed a resolution approving the Yucca Mountain
site after receiving the approval of this site from the U.S. Senate and House of Representatives. This action allows the Department of Energy to apply to the NRC to license the project. The Department
of Energy expects that this facility will open in 2010. However, the opening of Yucca Mountain could be delayed due to multiple lawsuits initiated by the State of Nevada and other interested parties,
the NRC licensing hearings, and other issues related to the site.

Nuclear Insurance

We maintain nuclear insurance coverage for Calvert Cliffs and Nine Mile Point in four program areas: liability, worker radiation, property, and accidental outage. These
policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear, and war.

In
November 2002, the President signed into law the Terrorism Risk Insurance Act ("TRIA") of 2002. Under the TRIA, property and casualty insurance companies are required to offer
insurance for losses resulting from Certified acts of terrorism. Certified acts of terrorism are determined by the Secretary of State and Attorney General and primarily are based upon the occurrence
of significant acts of international terrorism. Our nuclear property and accidental outage insurance programs, as discussed later in this section, provide coverage for Certified acts of terrorism.

Losses
resulting from non-certified acts of terrorism are covered as a common occurrence, meaning that if non-certified terrorist acts occur against one or more commercial nuclear power
plants insured by our insurance company within a 12-month period, they would be treated as one event and the owners of the plants would share one full limit of liability (currently
$3.24 billion).

If
there were an accident or an extended outage at any unit of Calvert Cliffs or Nine Mile Point, it could have a substantial adverse financial effect on us.

Nuclear Liability Insurance

Pursuant to the Price-Anderson Act, we are required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability,
approximately $9.6 billion. This limit of liability consists of the maximum available commercial insurance of $300 million and the remaining $9.3 billion is provided through
mandatory participation in an industry-wide retrospective assessment program. Under this retrospective assessment program, we can be assessed up to $352.4 million per incident at
any commercial reactor in the country, payable at no more than $40 million per incident per year. This assessment also applies in excess of our worker radiation claims insurance and is subject
to inflation and state premium taxes. In addition, the U.S. Congress could impose additional revenue-raising measures to pay claims.

The
Price-Anderson Act expired in August 2002. However, the Price-Anderson Act will remain in effect in its current form for existing reactors until it is renewed. A renewal bill
was introduced in Congress in January 2003 to extend the Act for 15 years from August 1, 2002. The bill proposes a change in the annual retrospective premium limit from
$10 million to $15 million per reactor per incident and a change in the maximum potential assessment from $88.1 million to $98.7 million per reactor per incident. If
approved, these changes would increase the amount we could be assessed to $394.8 million per incident, payable at no more than $60 million per incident per year. We do not know what
impact any other changes to the Act may have on us until a final resolution is reached.

Worker Radiation Claims Insurance

We participate in the American Nuclear Insurers Master Worker Program that provides coverage for worker tort claims filed for radiation injuries. Effective January 1,
1998, this program was modified to provide coverage to all workers whose nuclear-related employment began on or after the commencement date of reactor operations. Waiving the right to make additional
claims under the old policy was a condition for coverage under the new policy. We describe the old and new policies below:



106

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The
sellers of Nine Mile Point retain the liabilities for existing and potential claims that occurred prior to November 7, 2001. In addition, the Long Island Power Authority,
which continues to own 18% of Unit 2 at Nine Mile Point, is obligated to assume its pro rata share of any liabilities for retrospective premiums and other premiums assessments. If claims under these
policies exceed the coverage limits, the provisions of the Price-Anderson Act would apply.

Nuclear Property Insurance

Our policies provide $500 million in primary and an additional $2.25 billion in excess coverage for property damage, decontamination, and premature
decommissioning liability for Calvert Cliffs or Nine Mile Point. This coverage currently is purchased through an industry mutual insurance company. If accidents at plants insured by the mutual
insurance company cause a shortfall of funds, all policyholders could be assessed, with our share being up to $56.2 million.

Accidental Nuclear Outage Insurance

Our policies provide indemnification on a weekly basis for losses resulting from an accidental outage of a nuclear unit. Coverage begins after a 12-week deductible
period and continues at 100% of the weekly indemnity limit for 52 weeks and then 80% of the weekly indemnity limit for the next 110 weeks. Our coverage is up to $490.0 million per unit at
Calvert Cliffs, $335.4 million for Unit 1 of Nine Mile Point, and $412.6 million for Unit 2 of Nine Mile Point. This amount can be reduced by up to $98.0 million per unit at
Calvert Cliffs and $82.5 million for Nine Mile Point if an outage of more than one unit is caused by a single insured physical damage loss.

Non-Nuclear Property Insurance

Our conventional property insurance provides coverage of $1.0 billion per occurrence for Certified acts of terrorism as defined under the TRIA.

Losses
resulting from non-certified acts of terrorism are covered by an industry mutual insurance program. This program, which expires May 1, 2003, provides limits of
$50 million per occurrence and is subject to a term aggregate limit of $100 million. These limits are shared among all companies participating in the program. The mutual insurer may
renew this program depending upon the availability of reinsurance at the program's expiration. If terrorist acts at any of our facilities result in a loss exceeding this coverage, it could have a
significant adverse impact on our financial results.

California Power Purchase Agreements

Our merchant energy business has $260.6 million invested in operating power projects of which our ownership percentage represents 137 megawatts of electricity that are
sold to Pacific Gas & Electric (PGE) and to Southern California Edison (SCE) in California under power purchase agreements.

As
a result of ongoing litigation before the FERC regarding sales into the spot markets of the California Independent System Operator and Power Exchange, we estimate that we may be
required to pay refunds of between $3 and $4 million for transactions that we entered into with these entities for the period between October 2000 and June 2001. However, our
estimate is based on current information, and because litigation is ongoing, new events could occur that could cause the actual amount, if any, to be materially different from our estimate.

107

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12Hedging Activities and Fair Value of Financial Instruments

SFAS No. 133 Hedging Activities

We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price and transportation costs of electricity, natural gas, and
other commodities.

Interest Rates

We use interest rate swaps to manage our interest rate exposures associated with new debt issuances. These swaps are designated as cash-flow hedges under SFAS
No. 133 in anticipation of planned financing transactions as discussed inNote 1. The notional amounts of the contracts do not represent
amounts that are exchanged by the parties and are not a measure of our exposure to market or credit risks. The notional amounts are used in the determination of the cash settlements under the
contracts.

Prior
to the March 2002 issuance of $1.8 billion of debt as discussed inNote 8, we entered into various forward
starting interest rate swap contracts to manage our interest rate exposure related to this debt issuance. In 2001, we entered into swaps that had notional or contract amounts that totaled
$800 million with an average rate of 4.9%. At December 31, 2001, the fair value of these swaps was an unrealized pre-tax gain of $36.3 million. In the first quarter of
2002, we entered into additional forward starting interest rate swaps with notional amounts that totaled $700 million with an average rate of 5.9%. All of these swap contracts expired at the
end of March 2002 with a gain of $53.7 million.

In
addition, we entered into forward starting interest rate swap contracts with notional amounts that totaled $400 million with an average rate of 5.1% to manage our interest rate
exposure related to the issuance of $500 million of debt in 2002 as discussed inNote 8. These swap contracts expired in 2002 with a loss
of $16.7 million.

We
will reclassify the $37.0 million net gain from these swaps from "Accumulated other comprehensive income" into "Interest expense" and include them in earnings during the
periods in which the hedged interest payments occur. We expect to reclassify $3.7 million of pre-tax net gains related to our expired swap contracts from "Accumulated other
comprehensive income" into "Interest expense" in 2003.

Commodity Prices

Our origination and risk management operation uses a variety of derivative and non-derivative instruments to 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 energy and purchases of fuel and energy,
including:



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.

At
December 31, 2002, our merchant energy business had designated certain fixed-price forward contracts as cash-flow hedges of forecasted sales of energy and
forecasted purchases of fuel and energy for the years 2003 through 2010 under SFAS No. 133.

At
December 31, 2002, our merchant energy business recorded net unrealized pre-tax losses of $45.3 million on these hedges, net of associated deferred income
tax effects, in "Accumulated other comprehensive income." We expect to reclassify $24.7 million of net pre-tax gains on cash-flow hedges from "Accumulated other
comprehensive income" into earnings during the next twelve months based on the market prices at December 31, 2002. However, the actual amount reclassified into earnings could vary from the
amounts recorded at December 31, 2002 due to future changes in market prices. In 2002, we recognized $1.4 million of losses in earnings related to hedge ineffectiveness.

108

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Fair Value of Financial Instruments

The fair value of a financial instrument represents the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a
forced sale or liquidation. Significant differences can occur between the fair value and carrying amount of financial instruments that are recorded at historical amounts. We use the following methods
and assumptions for estimating fair value disclosures for financial instruments:



We
show the carrying amounts and fair values of financial instruments included in our Consolidated Balance Sheets in the following table, and we describe some of the items separately
later in this Note.

|At December 31,                               |                                        | 2002 |         | 2001 
|--------------------------------------------- | -------------------------------------- | ---- | ------- | -----
|
|
|
|
|Investments and other assets for which it is: |                                        |      |         |      
|                                              | Practicable to estimate fair value     |      | $       | 755.1
|                                              | Not practicable to estimate fair value |      |         | 24.2 
|Fixed-rate long-term debt                     |                                        |      | 4,713.9 |      
|Variable-rate long-term debt                  |                                        |      | 335.9   |      

It
was not practicable to estimate the fair value of investments held by our nonregulated businesses in several financial partnerships that invest in nonpublic debt and equity
securities. This is because the timing and amount of cash flows from these investments are difficult to predict. We report these investments at their original cost in our Consolidated Balance Sheets.

The
investments in financial partnerships totaled $24.2 million at December 31, 2002, representing ownership interests up to 10% and $25.8 million at
December 31, 2001, representing ownership interests up to 11%. The total assets of all of these partnerships totaled $5.8 billion at December 31, 2001 (which is the latest
information available).

---

13Stock-Based Compensation

Under
our long-term incentive plans, we granted stock options, performance and service-based restricted stock, and equity to officers, key employees, and members of the Board of Directors.
Under the plans, we can grant up to a total of 18,000,000 shares. At December 31, 2002, we had stock options and restricted stock grants outstanding as discussed below.

Non-Qualified Stock Options

Options are granted at prices not less than the market value of the common stock at the date of grant, become vested over a period up to five years, and expire ten years from
the date of grant. In accordance with APB No. 25, no compensation expense is recognized for these stock option awards.

In
February 2002, our Committee on Management of the Board of Directors granted options, contingent on shareholder approval of our long-term incentive plan, with an
exercise price equal to fair market value of our stock on the date of grant of $27.93. Our shareholders approved the plan at the annual meeting in May 2002 when then stock price had increased
to $31.21. The difference between the exercise price and the fair market value in May when the shareholder approval contingency was satisfied was $6.3 million and is being amortized to
compensation expense over a period up to five years. In 2002, we recorded compensation expense of $3.0 million related to this grant.

109

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All
other stock options grants have an exercise price equal to or greater than market value on the date of grant and were not subject to any future contingencies, therefore no
compensation expense has been recognized. We reverse any expense associated with stock options that are canceled or forfeited prior to the vesting of the grants. Summarized information for our stock
option grants is as follows:

|                                                                               |                                                                       | 2002                                                                  |      | 2001  |       | 2000  |      
|------------------------------------------------------------------------------ | --------------------------------------------------------------------- | --------------------------------------------------------------------- | ---- | ----- | ----- | ----- | -----
|
|
|
|Outstanding, beginning of year                                                 |                                                                       | 2,646                                                                 |      | $     | 30.73 |       | 2,420
|                                                                               | Granted with Exercise Prices:                                         |                                                                       |      |       |       |       |      
|                                                                               |                                                                       | At fair market value                                                  |      | 1,708 |       |       | 30.62
|                                                                               |                                                                       | Less than fair market value on the date contingency was satisfied (1) |      | 1,935 |       |       | 27.93
|                                                                               |                                                                       | Greater than fair market value                                        |      | 103   |       |       | 31.21
|                                                                               |                                                                      
|                                                                               |                                                                       | Total granted                                                         |      | 3,746 |       |       | 29.25
|                                                                               | Exercised                                                             |                                                                       |     |       |       |      |      
|                                                                               | Canceled/Expired                                                      |                                                                       | (311 | )     |       | 34.01 |      
|                                                                               |                                                                      
|Outstanding, end of year                                                       |                                                                       | 6,081                                                                 |      | $     | 29.65 |       | 2,646
|                                                                               |                                                                      
|Exercisable, end of year                                                       |                                                                       | 1,413                                                                 |      | $     | 30.78 |       | 235  
|                                                                               |                                                                      
|Weighted-average fair value per share of options granted with Exercise Prices: |                                                                       | 2002                                                                  |      | 2001  |       | 2000  |      
|                                                                               | At fair market value                                                  |                                                                       |      |       | $     | 7.79  |      
|                                                                               | Less than fair market value on the date contingency was satisfied (1) |                                                                       |      |       | $     | 9.15  |      
|                                                                               | Greater than fair market value                                        |                                                                       |      |       | $     | 5.89  |      
|                                                                               |                                                                      

The
following table summarizes information about stock options outstanding at December 31, 2002 (shares in thousands):

|Range of Exercise Prices |  | Number
Outstanding |  | Weighted-Average
Remaining
Contractual Life |  | Number
Exercisable
|------------------------ |  | ------------------ |  | ------------------------------------------- |  | ------------------
|
|$21.4734.25             |  | 6,081              |  | 8.8 years                                   |  | 1,413             

Restricted Stock Awards

In addition, we issue common stock based on meeting certain performance and/or service goals. This stock vests to participants at various times ranging from one to five years
if the performance and/or service goals are met. In accordance with APB No. 25, we recognize compensation expense for our performance-based awards using the variable accounting method, whereby
we amortize the value of the market price of the underlying stock on the date of grant adjusted for subsequent changes in fair market value through the lapse date to compensation expense over the
performance period. We account for our service-based awards using the fixed accounting method, whereby we amortize the value of the market price of the underlying stock on the date of grant to
compensation expense over the service period. We reverse any expense associated with restricted stock that is canceled or forfeited during the performance or service period.

110

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We
recorded compensation expense related to our restricted stock awards of $6.6 million in 2002 and $16.3 million in 2000. In 2001, due to non-attainment of
performance criteria, we recorded a reduction to compensation expense of $10.1 million. Summarized share information for our restricted stock awards is as follows:

|                                                     |                          | 2002 |       | 2001 |   | 2000  |    
|---------------------------------------------------- | ------------------------ | ---- | ----- | ---- | - | ----- | ---
|
|
|Outstanding, beginning of year                       |                          |      | 435   |      |   | 377   |    
|                                                     | Granted                  |      |       | 344  |   |       | 87 
|                                                     | Released to participants |      |       | (170 | ) |       |   
|                                                     | Canceled                 |      |       | (295 | ) |       | (29
|                                                     |                         
|Outstanding, end of year                             |                          |      | 314   |      |   | 435   |    
|                                                     |                         
|Weighted-average fair value restricted stock granted |                          | $    | 27.23 |      | $ | 35.24 |    
|                                                     |                         

Equity-Based Grants

In 2002, we recorded compensation expense of $0.5 million related to equity-based grants to members of the Board of Directors.

Pro-forma Information

Disclosure of pro-forma information regarding net income and earnings per share is required under SFAS No. 123, which uses the fair value method. The fair
values of our stock-based awards were estimated as of the date of grant using the Black-Scholes option pricing model based on the following weighted-average assumptions:

|                                         |  | 2002 |   | 2001 |   | 2000 |  
|---------------------------------------- |  | ---- | - | ---- | - | ---- | -
|
|Risk-free interest rate                  |  | 4.45 | % | 4.79 | % | 6.73 | %
|Expected life (in years)                 |  | 5.0  |   | 5.0  |   | 10.0 |  
|Expected market price volatility factors |  | 31.9 | % | 41.3 | % | 21.0 | %
|Expected dividend yields                 |  | 3.3  | % | 1.8  | % | 5.7  | %

We
disclose the pro-forma effect on net income and earnings per share in accordance with SFAS No. 148,Accounting for Stock-Based
CompensationTransition and Disclosure, inNote 1.

---

14Acquisitions

Acquisition of Alliance

On December 31, 2002, we purchased Alliance Energy Services, LLC and Fellon-McCord Associates, Inc. (collectively, Alliance) from Allegheny Energy, Inc.
These businesses provide gas supply and transportation services and energy consulting services to large commercial and industrial customers primarily in the Midwest region, but also in other
competitive energy markets including the Northeast, Mid-Atlantic, Texas and California regions. We acquired 100% ownership of these companies for a note payable of $21.2 million
that was settled in cash on January 2, 2003. We acquired cash of $4.6 million as part of the purchase. We include these companies in our merchant energy business segment.

Our
preliminary purchase price allocation for the net assets acquired is as follows:

|At December 31, 2002                   |  |  
|-------------------------------------- |  | -
|
|
|Cash                                   |  | $
|Other Current Assets                   |  |  
|                                      
|Total Current Assets                   |  |  
|Net Property, Plant and Equipment      |  |  
|Goodwill                               |  |  
|Other Assets                           |  |  
|                                      
|Total Assets Acquired                  |  |  
|Current Liabilities                    |  |  
|Deferred Credits and Other Liabilities |  |  
|                                      
|Net Assets Acquired                    |  | $
|                                      

111

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We
recorded the existing contracts at fair value as part of the purchase price allocation. The preliminary net fair value of the contracts was $4.0 million. We recorded the fair
value of these contracts as follows:

|Net fair value of acquired contracts |  |  
|------------------------------------ |  | -
|
|
|Current Assets                       |  | $
|Noncurrent Assets                    |  |  
|                                    
|Total Assets                         |  |  
|                                    
|Current Liabilities                  |  |  
|Noncurrent Liabilities               |  |  
|                                    
|Total Liabilities                    |  |  
|                                    
|Net fair value of acquired contracts |  | $
|                                    

We
will amortize this value over a period extending through 2005. The weighted-average amortization period is approximately one year and represents the expected contract duration.

There
are further refinements to the preliminary valuation of the existing contracts that have not been finalized that could impact our purchase price allocation.

On
an unaudited pro-forma basis, had the acquisition of Alliance occurred on the first day of each of the years presented below, our nonregulated revenues and total revenues
would have been as follows:

|Year Ended December 31, |             | 2002 |   | 2001    |  | 2000
|----------------------- | ----------- | ---- | - | ------- |  | ----
|
|
|Nonregulated revenues   |             |      |   |         |  |     
|                        | As reported |      | $ | 2,166.9 |  | $   
|                        | Pro-forma   |      |   | 2,706.6 |  |     
|Total revenues          |             |      |   |         |  |     
|                        | As reported |      | $ | 4,703.0 |  | $   
|                        | Pro-forma   |      |   | 5,242.7 |  |     

We
believe that the pro-forma impact on "Income before cumulative effect of change in accounting principle," "Net income," and "Earnings per common share" would not have been
material had the acquisition of Alliance occurred on the first day of each of the years presented.

Acquisition of NewEnergy

On September 9, 2002, we purchased AES NewEnergy, Inc. from AES Corporation. Subsequent to the acquisition, we renamed AES NewEnergy, Inc. as Constellation
NewEnergy, Inc. (NewEnergy). NewEnergy is a leading national provider of electricity, natural gas, and energy services, serving approximately 4,300 megawatts of load associated with large
commercial and industrial customers in competitive energy markets including the Northeast, Mid-Atlantic, Midwest, Texas and California. We acquired 100% ownership of NewEnergy for cash of
$250.3 million, including $1.4 million of direct costs associated with the acquisition. We acquired cash of $45.5 million as part of the purchase. We include NewEnergy in our
merchant energy business segment.

Our
preliminary purchase price allocation for the net assets acquired is as follows:

|At September 9, 2002                   |  |  
|-------------------------------------- |  | -
|
|
|Cash                                   |  | $
|Other Current Assets                   |  |  
|                                      
|Total Current Assets                   |  |  
|Net Property, Plant and Equipment      |  |  
|Goodwill                               |  |  
|Other Assets                           |  |  
|                                      
|Total Assets Acquired                  |  |  
|Current Liabilities                    |  |  
|Deferred Credits and Other Liabilities |  |  
|                                      
|Net Assets Acquired                    |  | $
|                                      

We
recorded the existing contracts at fair value as part of the purchase price allocation. The preliminary net fair value of the contracts was $54.8 million. We recorded the fair
value of these contracts as follows:

|Net fair value of acquired contracts |  |  
|------------------------------------ |  | -
|
|
|Current Assets                       |  | $
|Noncurrent Assets                    |  |  
|                                    
|Total Assets                         |  |  
|                                    
|Current Liabilities                  |  |  
|Noncurrent Liabilities               |  |  
|                                    
|Total Liabilities                    |  |  
|                                    
|Net fair value of acquired contracts |  | $
|                                    

We
will amortize this value over a period extending through 2007. The weighted-average amortization period is approximately 2 years and represents the expected contract duration.

112

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Currently,
the following items have not been finalized that could impact our purchase price allocation:



On
an unaudited pro-forma basis, had the acquisition of NewEnergy occurred on the first day of each of the years presented below, our nonregulated revenues and total revenues
would have been as follows:

|Year Ended December 31, |             | 2002 |   | 2001    |  | 2000
|----------------------- | ----------- | ---- | - | ------- |  | ----
|
|
|Nonregulated revenues   |             |      |   |         |  |     
|                        | As reported |      | $ | 2,166.9 |  | $   
|                        | Pro-forma   |      |   | 3,307.7 |  |     
|Total revenues          |             |      |   |         |  |     
|                        | As reported |      | $ | 4,703.0 |  | $   
|                        | Pro-forma   |      |   | 5,843.8 |  |     

We
believe that the pro-forma impact on "Income before cumulative effect of change in accounting principle," "Net income," and "Earnings per common share" would not have been
material had the acquisition of NewEnergy occurred on the first day of each of the years presented.

Acquisition of Nine Mile Point

On November 7, 2001, we completed our purchase of Nine Mile Point located in Scriba, New York. Nine Mile Point consists of two boiling-water reactors. Unit 1 is a
609-megawatt reactor that entered service in 1969. Unit 2 is a 1,148-megawatt reactor that began operation in 1988.

Nine
Mile Point Nuclear Station, LLC, a subsidiary of Constellation Nuclear, purchased 100 percent of Nine Mile Point Unit 1 and 82 percent of Unit 2. Approximately
one-half of the purchase price, or $380 million, in addition to settlement costs of $2.7 million, was paid at closing. The remainder was financed through the sellers in a
note to be repaid over five years with an interest rate of 11.0%. This note was prepaid in April 2002. The sellers also transferred to us approximately $442 million in decommissioning
funds. As a result of this purchase, we own 1,550 megawatts of Nine Mile Point's 1,757 megawatts of total generating capacity.

Niagara
Mohawk Power Corporation was the sole owner of Nine Mile Point Unit 1. The co-owners of Unit 2 who sold their interests are: Niagara Mohawk (41 percent), New
York State Electric and Gas (18 percent), Rochester Gas & Electric Corporation (14 percent), and Central Hudson Gas & Electric Corporation (9 percent). The Long
Island Power Authority will continue to own 18 percent of Unit 2.

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

Nine Mile Point Net Assets Acquired

|At November 7, 2001                    |  |  
|-------------------------------------- |  | -
|
|
|Current Assets                         |  | $
|Nuclear Decommissioning Trust Fund     |  |  
|Net Property, Plant and Equipment      |  |  
|Intangible Assets (details below)      |  |  
|                                      
|Total Assets Acquired                  |  |  
|Current Liabilities                    |  |  
|Deferred Credits and Other Liabilities |  |  
|                                      
|Net Assets Acquired                    |  |  
|Note to Sellers                        |  |  
|                                      
|Total Cash Paid                        |  | $
|                                      

The
intangible assets acquired consist of the following:

|Description                      |  | Amount |      | Weighted-
Average
Useful Life
|-------------------------------- |  | ------ | ---- | -----------------------------
|
|
|Operating procedures and manuals |  | $      | 22.3 |                              
|Permits and licenses             |  |        | 13.0 |                              
|Software                         |  |        | 2.3  |                              
|                                 |  |       
|Total intangible assets          |  | $      | 37.6 |                              
|                                 |  |       

113

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15Related Party TransactionsBGE

Income Statement

BGE is providing standard offer service to customers at fixed rates over various time periods during the transition period, July 1, 2000 to June 30, 2006, for
those customers that do not choose an alternate supplier. Our origination and risk management operation is under contract to provide BGE with the energy and capacity required to meet its standard
offer service obligations for the first three years of the transition period, and 90% of the energy and capacity for the final three years (July 1, 2003June 30, 2006) of the
transition period. The cost of BGE's purchased energy from nonregulated affiliates of Constellation Energy to meet its standard offer service obligation was $1,080.5 million for the year ended
December 31, 2002, $1,150.1 million for the year ended December 31, 2001, and $581.0 million for the year ended December 31, 2000.

In
addition, Constellation Energy charges BGE for the costs of certain corporate functions. Certain costs are directly assigned to BGE. We allocate other corporate function costs based
on a total percentage of expected use by BGE. Management believes this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity. These costs were
$32.2 million for the year ended December 31, 2002, $27.1 million for the year ended December 31, 2001, and $21.6 million for the year ended December 31,
2000.

Balance Sheet

BGE participates in a cash pool under a Master Demand Note agreement with Constellation Energy. Under this arrangement, participating subsidiaries may invest in or borrow from
the pool at market interest rates. Constellation Energy administers the pool and invests excess cash in short-term investments or issues commercial paper to manage consolidated cash
requirements. Under this arrangement, BGE had invested $338.1 million at December 31, 2002 and $439.1 million at December 31, 2001.

Amounts
related to corporate functions performed at the Constellation Energy holding company, BGE's purchases to meet its standard offer service obligation, and BGE's charges to
Constellation Energy and its nonregulated affiliates for certain services it provides them result in intercompany balances on BGE's Consolidated Balance Sheets.

Management
believes its allocation methods are reasonable and approximate the costs that would be charged to unaffiliated entities.

114

---

16Quarterly Financial Data (Unaudited)

Our
quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair presentation. Our utility business is seasonal in nature with the
peak sales periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.

2002 Quarterly DataConstellation Energy

|              |              | Revenues |   | Income from Operations |  | Earnings Applicable to Common Stock |         | Earnings Per Share of Common Stock
|------------- | ------------ | -------- | - | ---------------------- |  | ----------------------------------- | ------- | ----------------------------------
|
|
|Quarter Ended |              |          |   |                        |  |                                     |         |                                   
|              | March 31     |          | $ | 1,040.0                |  | $                                   | 418.6   |                                   
|              | June 30      |          |   | 1,020.8                |  |                                     | 184.9   |                                   
|              | September 30 |          |   | 1,270.3                |  |                                     | 308.0   |                                   
|              | December 31  |          |   | 1,371.9                |  |                                     | 174.7   |                                   
|             
|Year Ended    |              |          |   |                        |  |                                     |         |                                   
|              | December 31  |          | $ | 4,703.0                |  | $                                   | 1,086.2 |                                   
|             

2002 Quarterly DataBGE

|              |              | Revenues |   | Income from Operations |  | Earnings Applicable to Common Stock
|------------- | ------------ | -------- | - | ---------------------- |  | -----------------------------------
|
|
|Quarter Ended |              |          |   |                        |  |                                    
|              | March 31     |          | $ | 683.7                  |  | $                                  
|              | June 30      |          |   | 572.9                  |  |                                    
|              | September 30 |          |   | 668.5                  |  |                                    
|              | December 31  |          |   | 622.2                  |  |                                    
|             
|Year Ended    |              |          |   |                        |  |                                    
|              | December 31  |          | $ | 2,547.3                |  | $                                  
|             

First quarter results include:

Constellation Energy and BGE



Constellation Energy



Second
quarter results include:

Constellation Energy and BGE



Constellation Energy



Third
quarter results include:

Constellation Energy and BGE



Constellation Energy



Fourth
quarter results include:

Constellation Energy and BGE



Constellation Energy



We
discuss our special items inNote 2.

The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and dilution as a result of issuing common shares during
the year.

115

---

2001 Quarterly DataConstellation Energy

|              |              | Revenues |   | Income from Operations |  | Earnings Applicable to Common Stock |        | Earnings Per Share of Common Stock |  
|------------- | ------------ | -------- | - | ---------------------- |  | ----------------------------------- | ------ | ---------------------------------- | -
|
|
|Quarter Ended |              |          |   |                        |  |                                     |        |                                    |  
|              | March 31     |          | $ | 1,130.5                |  | $                                   | 235.0  |                                    | $
|              | June 30      |          |   | 826.1                  |  |                                     | 171.0  |                                    |  
|              | September 30 |          |   | 1,043.4                |  |                                     | 317.5  |                                    |  
|              | December 31  |          |   | 878.8                  |  |                                     | (365.7 | )                                  |  
|              |             
|Year Ended    |              |          |   |                        |  |                                     |        |                                    |  
|              | December 31  |          | $ | 3,878.8                |  | $                                   | 357.8  |                                    | $
|              |             

2001 Quarterly DataBGE

|              |              | Revenues |   | Income from Operations |  | Earnings Applicable to Common Stock |      
|------------- | ------------ | -------- | - | ---------------------- |  | ----------------------------------- | -----
|
|
|Quarter Ended |              |          |   |                        |  |                                     |      
|              | March 31     |          | $ | 849.9                  |  | $                                   | 141.1
|              | June 30      |          |   | 607.1                  |  |                                     | 74.7 
|              | September 30 |          |   | 701.4                  |  |                                     | 80.4 
|              | December 31  |          |   | 562.3                  |  |                                     | 15.6 
|              |             
|Year Ended    |              |          |   |                        |  |                                     |      
|              | December 31  |          | $ | 2,720.7                |  | $                                   | 311.8
|              |             

First quarter results include:

Constellation Energy



Second
quarter results include:

Constellation Energy



Third
quarter results include:

Constellation Energy



Fourth
quarter results include:

Constellation Energy and BGE



Constellation Energy



We
discuss our special items inNote 2.

The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and dilution as a result of issuing common shares during
the year.

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

116

---

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

---

PART III

BGE meets the conditions set forth in General Instruction I(1)(a)and (b) of Form 10-K for a reduced disclosure format. Accordingly,
all items in this section related to BGE are not presented.

Item 10. Directors and Executive Officers of the Registrant

The information required by this item with respect to directors is set forth underElection of Constellation Energy Directorsin
the Proxy Statement and is incorporated herein by reference.

The
information required by this item with respect to executive officers of Constellation Energy Group, pursuant to instruction 3 of paragraph (b) of Item 401 of
Regulation S-K, is set forth in Item 4 of Part I of this Form 10-K underExecutive Officers of the
Registrant.

Item 11. Executive Compensation

The information required by this item is set forth underDirectors' Compensation,Compensation Committee
Interlocks and Insider Participation,Executive Compensation,Common Stock Performance
GraphandReport of Committee on Management on Executive Compensationin the Proxy Statement and is incorporated herein by
reference.

---

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

Equity Compensation Plan Information

|                                                           |  | (a)   |  | (b) |       | (c)
|---------------------------------------------------------- |  | ----- |  | --- | ----- | ---
|
|
|
|Equity compensation plans approved by security holders     |  | 3,769 |  | $   | 29.60 |    
|Equity compensation plans not approved by security holders |  | 2,312 |  | $   | 29.74 |    
|                                                          
|Total                                                      |  | 6,081 |  | $   | 29.65 |    
|                                                          

The
plans that do not require security holder approval are the Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan (Designated as Exhibit
No. 10(u)) and the Constellation Energy Group, Inc. Management Long-Term Incentive Plan (Designated as Exhibit No. 10(v)). Under these plans, we may grant up to a
total of 7,000,000 equity shares. We have granted stock options and performance and service-based restricted stock to officers and key employees.

The
additional information required by this item is set forth underSecurity Ownershipin the Proxy Statement and is incorporated herein
by reference.

Item 13. Certain Relationships and Related Transactions

The additional information required by this item is set forth underCertain Relationships and Transactionsin the Proxy
Statement and is incorporated herein by reference.

Item 14. Internal Controls and Procedures

Within the 90-day period prior to the filing of this report, an evaluation was carried out under the supervision and with the participation of management, including
the principal executive officers and principal financial officer of both Constellation Energy and BGE, of the effectiveness of the design and operation of their disclosure controls and procedures (as
defined in Rule 13a-14(c) under the Securities Exchange Act of 1934.) Based on that evaluation, such officers have concluded that the design and operation of Constellation Energy's
and BGE's disclosure controls and procedures were effective.

No
significant changes were made in either Constellation Energy's or BGE's internal controls or in other factors that could significantly affect such controls subsequent to the date of
their evaluation.

117

---



PART IV

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K

|   |  | (a) The following documents are filed as a part of this Report:                                                                                   
|-- |  | --------------------------------------------------------------------------------------------------------------------------------------------------
|1. |  | Financial Statements:                                                                                                                             
|   |  | Report of Independent Accountants dated January 29, 2003 of PricewaterhouseCoopers LLP                                                            
|   |  | Consolidated Statements of IncomeConstellation Energy Group for three years ended December 31, 2002                                              
|   |  | Consolidated Balance SheetsConstellation Energy Group at December 31, 2002 and December 31, 2001                                                 
|   |  | Consolidated Statements of Cash FlowsConstellation Energy Group for three years ended December 31, 2002                                          
|   |  | Consolidated Statements of Common Shareholders' Equity and Comprehensive IncomeConstellation Energy Group for three years ended December 31, 2002
|   |  | Consolidated Statements of CapitalizationConstellation Energy Group at December 31, 2002 and December 31, 2001                                   
|   |  | Consolidated Statements of IncomeBaltimore Gas and Electric Company for three years ended December 31, 2002                                      
|   |  | Consolidated Balance SheetsBaltimore Gas and Electric Company at December 31, 2002 and December 31, 2001                                         
|   |  | Consolidated Statements of Cash FlowsBaltimore Gas and Electric Company for three years ended December 31, 2002                                  
|   |  | Notes to Consolidated Financial Statements                                                                                                        
|2. |  | Financial Statement Schedules:                                                                                                                    
|   |  | Schedule IIValuation and Qualifying Accounts                                                                                                     
|   |  | Schedules other than Schedule II are omitted as not applicable or not required.                                                                   
|3. |  | Exhibits Required by Item 601 of Regulation S-K.                                                                                                  

|Exhibit Number |     |   |  |                                                                                                                                                                                                                                              
|-------------- | --- | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|*2             |     |  |  | Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 in Form S-4 dated March 3, 1999, File No.
33-64799.)        
|*2             | (a) |  |  | Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit
No. 2(a) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)                                                                      
|*2             | (b) |  |  | Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)                                                                       
|*3             | (a) |  |  | Articles of Amendment and Restatement of the Charter of Constellation Energy Group, Inc. as of
April 30, 1999. (Designated as Exhibit No. 99.2 in Form 8-K dated April 30, 1999, File No. 1-1910.)                                           
|*3             | (b) |  |  | Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999. (Designated as Exhibit No. 3(a) in Form 10-Q dated August 13, 1999, File Nos. 1-12869 and 1-1910.)                                           
|*3             | (c) |  |  | Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999. (Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos.
1-12869 and 1-1910.)
|*3             | (d) |  |  | Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 in Form 10-Q dated November 14, 1996, File No. 1-1910.)                                                                                                         
|*3             | (e) |  |  | Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 20, 2001. (Designated as Exhibit No. 3(e) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869
and 1-1910.)    
|3              | (f) |  |  | Bylaws of Constellation Energy Group, Inc., as amended to January 24, 2003.                                                                                                                                                                  
|*3             | (g) |  |  | Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 in Form 10-Q dated November 13, 1998, File No. 1-1910.)                                                                                                          

118

---

|*4 | (a) |  |  | Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) in Form S-3 dated March 29, 1999, File
No. 333-75217.)                                                                                                                                                      
|-- | --- | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|*4 | (b) |  |  | First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003. (Designated as Exhibit No. 4(b) in Form S-3 dated January 24, 2003, File No.
333-102723.)                                                                                                                              
|*4 | (c) |  |  | Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 in Form 10-Q
dated August 11, 1995, File No. 1-1910); and the following Supplemental Indentures between BGE and Bankers Trust Company, Trustee:

|Dated              |  | File No. |  | Designated In                       |  | Exhibit
Number
|------------------ |  | -------- |  | ----------------------------------- |  | --------------
|*January 15, 1992  |  | 33-45259 |  | (Form S-3 Registration)             |  | 4(a)(ii)      
|*February 15, 1993 |  | 1-1910   |  | (Form 10-K Annual Report for 1992)  |  | 4(a)(i)       
|*March 1, 1993     |  | 1-1910   |  | (Form 10-K Annual Report for 1992)  |  | 4(a)(ii)      
|*March 15, 1993    |  | 1-1910   |  | (Form 10-K Annual Report for 1992)  |  | 4(a)(iii)     
|*April 15, 1993    |  | 1-1910   |  | (Form 10-Q dated May 13, 1993)      |  | 4             
|*July 1, 1993      |  | 1-1910   |  | (Form 10-Q dated August 13, 1993)   |  | 4(a)          
|*October 15, 1993  |  | 1-1910   |  | (Form 10-Q dated November 12, 1993) |  | 4             
|*June 15, 1996     |  | 1-1910   |  | (Form 10-Q dated August 13, 1996)   |  | 4             

|*4  | (d) |  |  | Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as
of October 1, 1987 (Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
|--- | --- | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|*4  | (e) |  |  | Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures. (Designated as Exhibit 4(d) in Form S-3 dated May 28, 1998,
File No. 333-53767.)                                                                                                                                                                                                                             
|*4  | (f) |  |  | Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures. (Designated as Exhibit 4(e) in Form S-3 dated May 28, 1998,
File No. 333-53767.)                                                                                                                                                                                                                            
|*4  | (g) |  |  | Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) in Form S-3 dated May 28, 1998, File No. 333-53767.)                                                                                                                                                                                                                                                                                                                                                     
|*4  | (h) |  |  | Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) in Form S-3 dated May 28, 1998, File No. 333-53767.)                                                                                                                                                                                                                                                                                                                                                      
|*4  | (i) |  |  | Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) in Form S-3 dated May 28, 1998, File No. 333-53767.)                                                                                                                                                                                                                                                                                                   
|*10 | (a) |  |  | Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated. (Designated as Exhibit No. 10(a) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and
1-1910.)                                                                                                                                                                                                                                       
|*10 | (b) |  |  | Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 2000, File Nos. 1-12869 and
1-1910.)                                                                                                                                                                                                                                            
|10  | (c) |  |  | Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated.                                                                                                                                                                                                                                                                                                                                                                          
|*10 | (d) |  |  | Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(d) to the Annual Report on Form 10-K for the year ended December 31, 2001,
File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                    
|*10 | (e) |  |  | Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(m) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                    

119

---

|*10 | (f) |  |  | Summary of severance arrangement for Edward A. Crooke. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)                                                                                                                                  
|--- | --- | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|*10 | (g) |  |  | Grantor Trust Agreement Dated as of January 1, 2001 between Constellation Energy Group, Inc. and Citibank, N.A. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 2000, File
Nos. 1-12869 and 1-1910.)                                                                         
|10  | (h) |  |  | Form of Severance Agreements between Constellation Energy Group, Inc. and the following named executive officers: Mayo A. Shattuck III, E. Follin Smith, and Frank O. Heintz.                                                                                                                                                   
|*10 | (i) |  |  | Grantor Trust Agreement dated as of April 30, 1999 between Constellation Energy Group, Inc. and
T. Rowe Price Trust Company. (Designated as Exhibit No. 10(e) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)                                                                                                   
|*10 | (j) |  |  | Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 10-Q dated August 14, 2000, File Nos. 1-12869 and 1-1910.)
(Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)         
|*10 | (k) |  |  | Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 10-Q dated September 30, 2001, File Nos. 1-12869 and
1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)      
|*10 | (l) |  |  | Full Requirements Service Agreement between Baltimore Gas and Electric Company and Allegheny Energy Supply Company, L.L.C. (Designated as Exhibit No. 10(b) in Form 10-Q dated September 30, 2001, File Nos. 1-12869 and
1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
|*10 | (m) |   |  | Constellation Energy Group, Inc. Benefits Restoration Plan, as amended and restated. (Designated as Exhibit No. 10(m) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and
1-1910.)                                                                                                    
|*10 | (n) |  |  | Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated. (Designated as Exhibit No. 10(n) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and
1-1910.)                                                                                                    
|*10 | (o) |  |  | Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated. (Designated as Exhibit No. 10(o) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and
1-1910.)                                                                                           
|*10 | (p) |  |  | Constellation Energy Group, Inc. Supplemental Benefits Plan, as amended and restated. (Designated as Exhibit No. 10(p) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and
1-1910.)                                                                                                   
|10  | (q) |  |  | Compensation agreements between Constellation Energy Group, Inc. and Michael J. Wallace (Attachment 1Employment Agreement; Attachment 2Severance Agreement.)                                                                                                                                                                  
|*10 | (r) |  |  | Compensation agreements between Constellation Energy Group, Inc. and Thomas V. Brooks (Attachment 1Offer letter; Attachment 2Equity letter; Attachment 3Retention plan summary.) (Designated as Exhibit No.
10(r) to the Annual Report on Form 10-K for the year ended December 31, 2001, File
Nos. 1-12869 and 1-1910.)     
|10  | (s) |  |  | Constellation Energy Group, Inc. Executive Long-Term Incentive Plan.                                                                                                                                                                                                                                                            
|*10 | (t) |  |  | Constellation Energy Group, Inc. 2002 Executive Annual Incentive Plan. (Designated as Exhibit No. II in the Definitive Proxy Statement on Schedule 14A filed on April 18, 2002.)                                                                                                                                                
|10  | (u) |  |  | Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan.                                                                                                                                                                                                                                               
|10  | (v) |  |  | Constellation Energy Group, Inc. Management Long-Term Incentive Plan.                                                                                                                                                                                                                                                           
|10  | (w) |  |  | Compensation agreements between Constellation Energy Group, Inc. and E. Follin Smith (Attachment 1. Offer letter; Attachment 2Severance agreement.)                                                                                                                                                                            
|12  | (a) |  |  | Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.                                                                                                                                                                                                                            

120

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|12 | (b) |  |  | Baltimore Gas and Electric Company and Subsidiaries Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend
Requirements.
|-- | --- | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|21 |     |  |  | Subsidiaries of the Registrant.                                                                                                                                                                                         
|23 |     |  |  | Consent of PricewaterhouseCoopers LLP, Independent Accountants.                                                                                                                                                         

*
Incorporated by Reference.



None.

121

---



CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIESANDBALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIESSCHEDULE IIVALUATION AND QUALIFYING ACCOUNTS

|Column A                                                                    |                                          | Column B                                                          |  | Column C |        | Column D |   | Column E | 
|--------------------------------------------------------------------------- | ---------------------------------------- | ----------------------------------------------------------------- |  | -------- | ------ | -------- | - | -------- | 
|
|
|
|
|Reserves deducted in the Balance Sheet from the assets to which they apply: |                                          |                                                                   |  |          |        |          |   |          | 
|Constellation Energy                                                        |                                          |                                                                   |  |          |        |          |   |          | 
|                                                                            | Accumulated Provision for Uncollectibles |                                                                   |  |          |        |          |   |          | 
|                                                                            |                                          | 2002                                                              |  | $        | 22.8   |          | $ | 26.4     | 
|                                                                            |                                          | 2001                                                              |  |          | 21.3   |          |   | 26.5     | 
|                                                                            |                                          | 2000                                                              |  |          | 34.8   |          |   | 21.1     | 
|                                                                            | Valuation Allowance                     |                                                                   |  |          |        |          |   |          | 
|                                                                            |                                          | Net unrealized (gain) loss on available for sale securities       |  |          |        |          |   |          | 
|                                                                            |                                          | 2002                                                              |  |          | (243.7 | )        |   |         | 
|                                                                            |                                          | 2001                                                              |  |          | (33.7  | )        |   |         | 
|                                                                            |                                          | 2000                                                              |  |          | 0.2    |          |   |         | 
|                                                                            |                                          | Net unrealized (gain) loss on nuclear decommissioning trust funds |  |          |        |          |   |          | 
|                                                                            |                                          | 2002                                                              |  |          | (21.0  | )        |   |         | 
|                                                                            |                                          | 2001                                                              |  |          | (34.7  | )        |   |         | 
|                                                                            |                                          | 2000                                                              |  |          | (40.5  | )        |   |         | 
|                                                                            |                                          | Mark-to-market energy assets reserves                             |  |          |        |          |   |          | 
|                                                                            |                                          | 2002                                                              |  |          | (43.4  | )        |   |         | 
|                                                                            |                                          | 2001                                                              |  |          | (54.4  | )        |   |         | 
|                                                                            |                                          | 2000                                                              |  |          | (27.5  | )        |   |         | 
|BGE                                                                         |                                          |                                                                   |  |          |        |          |   |          | 
|                                                                            | Accumulated Provision for Uncollectibles |                                                                   |  |          |        |          |   |          | 
|                                                                            |                                          | 2002                                                              |  |          | 13.4   |          |   | 14.5     | 
|                                                                            |                                          | 2001                                                              |  |          | 13.4   |          |   | 21.8     | 
|                                                                            |                                          | 2000                                                              |  |          | 13.0   |          |   | 16.4     | 
|                                                                            |                                          | Net unrealized (gain) loss on nuclear decommissioning trust fund  |  |          |        |          |   |          | 
|                                                                            |                                          | 2002                                                              |  |          |       |          |   |         | 
|                                                                            |                                          | 2001                                                              |  |          |       |          |   |         | 
|                                                                            |                                          | 2000                                                              |  |          | (40.5  | )        |   |         | 

122

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Constellation Energy Group, Inc., the Registrant, has duly caused this Report to be signed on
its behalf by the undersigned, thereunto duly authorized.

| |                     |  | CONSTELLATION ENERGY GROUP, INC. (Registrant)                                    |    
| | ------------------- |  | -------------------------------------------------------------------------------- | ---
| | Date: March 7, 2003 |  | By                                                                               | /s/
| |                     |  | Mayo A. Shattuck IIIChairman of the Board, Chief Executive Officer
and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Constellation Energy Group, Inc., the Registrant,
and in the capacities and on the dates indicated.

|Signature                                   |                    | Title              |          | Date                                                                  
|------------------------------------------- | ------------------ | ------------------ | -------- | ----------------------------------------------------------------------
|                                            |                    |                    |          |                                                                       
|Principal executive officer and director:   |                    |                    |          |                                                                       
|By                                          | /s/                | M. A. Shattuck III |          | Chairman of the Board, Chief Executive Officer, President and Director
|
|Principal financial and accounting officer: |                    |                   
|By                                          | /s/                | E. F. Smith        |          | Senior Vice President and Chief Financial Officer                     
|
|Directors:                                  |                    |                    |          |                                                                       
|/s/                                         | D. L. Becker       |                    | Director |                                                                       
|
|/s/                                         | J. T. Brady        |                    | Director |                                                                       
|
|/s/                                         | F. P. Bramble, Sr. |                    | Director |                                                                       
|
|/s/                                         | B. B. Byron        |                    | Director |                                                                       
|
|/s/                                         | E. A. Crooke       |                    | Director |                                                                       
|
|/s/                                         | J. R. Curtiss      |                    | Director |                                                                       
|

123

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|/s/ | R. W. Gale           |  | Director |  | March 7, 2003
|--- | -------------------- |  | -------- |  | -------------
|
|/s/ | F. A. Hrabowski, III |  | Director |  | March 7, 2003
|
|/s/ | E. J. Kelly, III     |  | Director |  | March 7, 2003
|
|/s/ | N. Lampton           |  | Director |  | March 7, 2003
|
|/s/ | R. J. Lawless        |  | Director |  | March 7, 2003
|
|/s/ | M. D. Sullivan       |  | Director |  | March 7, 2003
|

124

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Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized.

| |                     | BALTIMORE GAS AND ELECTRIC COMPANY (Registrant) |                                                     
| | ------------------- | ----------------------------------------------- | ----------------------------------------------------
| | Date: March 7, 2003 |                                                 | By                                                  
| |                     |                                                 | Frank O. HeintzPresident and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company, the Registrant, and in
the capacities and on the dates indicated.

|Signature                                                |                    | Title        |          | Date                                                        
|-------------------------------------------------------- | ------------------ | ------------ | -------- | ------------------------------------------------------------
|                                                         |                    |              |          |                                                             
|Principal executive officer and director:                |                    |              |          |                                                             
|By                                                       | /s/                | F. O. Heintz |          | President, Chief Executive Officer, and Director            
|
|Principal financial and accounting officer and director: |                    |              |          |                                                             
|By                                                       | /s/                | E. F. Smith  |          | Senior Vice President, Chief Financial Officer, and Director
|
|Directors:                                               |                    |              |          |                                                             
|/s/                                                      | M. A. Shattuck III |              | Director |                                                             
|

125

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Certification

I, Mayo A. Shattuck III, certify that:

1.      I
have reviewed this annual report on Form 10-K of Constellation Energy Group, Inc.;

2.      Based
on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made,
in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.      Based
on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.      The
registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-14 and 15d-14) for the registrant and have:



5.      The
registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent functions):



6.      The
registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

March 7,
2003

|/s/MAYO A. SHATTUCK III                                                            |  | 
|---------------------------------------------------------------------------------- |  | 
|Mayo A. Shattuck III,
Chairman of the Board, Chief Executive Officer and President |  | 

126

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Certification

I, E. Follin Smith, certify that:

1.      I
have reviewed this annual report on Form 10-K of Constellation Energy Group, Inc.;

2.      Based
on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made,
in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.      Based
on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.      The
registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-14 and 15d-14) for the registrant and have:



5.      The
registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent functions):



6.      The
registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

March 7,
2003

|/s/E. FOLLIN SMITH                                                 |  | 
|------------------------------------------------------------------ |  | 
|E. Follin Smith,
Senior Vice President and Chief Financial Officer |  | 

127

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Certification

I, Frank O. Heintz, certify that:

1.      I
have reviewed this annual report on Form 10-K of Baltimore Gas and Electric Company;

2.      Based
on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made,
in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.      Based
on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.      The
registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-14 and 15d-14) for the registrant and have:



5.      The
registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent functions):



6.      The
registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

March 7,
2003

|/s/FRANK O. HEINTZ                                     |  | 
|------------------------------------------------------ |  | 
|Frank O. Heintz,
President and Chief Executive Officer |  | 

128

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Certification

I, E. Follin Smith, certify that:

1.      I
have reviewed this annual report on Form 10-K of Baltimore Gas and Electric Company;

2.      Based
on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made,
in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.      Based
on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.      The
registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-14 and 15d-14) for the registrant and have:



5.      The
registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent functions):



6.      The
registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

March 7,
2003

|/s/E. FOLLIN SMITH                                                 |  | 
|------------------------------------------------------------------ |  | 
|E. Follin Smith,
Senior Vice President and Chief Financial Officer |  | 

129

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EXHIBIT INDEX

|Exhibit Number |     |   |  |                                                                                                                                                                                                                                                                                                                                                              
|-------------- | --- | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|*2             |     |  |  | Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 in Form S-4 dated March 3, 1999, File No.
33-64799.)                                                                                                                        
|*2             | (a) |  |  | Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit
No. 2(a) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                      
|*2             | (b) |  |  | Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) in Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                       
|*3             | (a) |  |  | Articles of Amendment and Restatement of the Charter of Constellation Energy Group, Inc. as of
April 30, 1999. (Designated as Exhibit No. 99.2 in Form 8-K dated April 30, 1999, File No. 1-1910.)                                                                                                                                                           
|*3             | (b) |  |  | Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999. (Designated as Exhibit No. 3(a) in Form 10-Q dated August 13, 1999, File Nos. 1-12869 and 1-1910.)                                                                                                                                                           
|*3             | (c) |  |  | Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999. (Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos.
1-12869 and 1-1910.)                                                                                                                
|*3             | (d) |  |  | Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 in Form 10-Q dated November 14, 1996, File No. 1-1910.)                                                                                                                                                                                                                         
|*3             | (e) |  |  | Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 20, 2001. (Designated as Exhibit No. 3(e) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869
and 1-1910.)                                                                                                                    
|3              | (f) |  |  | Bylaws of Constellation Energy Group, Inc., as amended to January 24, 2003.                                                                                                                                                                                                                                                                                  
|*3             | (g) |  |  | Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 in Form 10-Q dated November 13, 1998, File No. 1-1910.)                                                                                                                                                                                                                          
|*4             | (a) |  |  | Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) in Form S-3 dated March 29, 1999, File
No. 333-75217.)                                                                                                                                                      
|*4             | (b) |  |  | First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003. (Designated as Exhibit No. 4(b) in Form S-3 dated January 24, 2003, File No.
333-102723.)                                                                                                                              
|*4             | (c) |  |  | Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 in Form 10-Q
dated August 11, 1995, File No. 1-1910); and the following Supplemental Indentures between BGE and Bankers Trust Company, Trustee:

|Dated              |  | File No. |  | Designated In                       |  | Exhibit
Number
|------------------ |  | -------- |  | ----------------------------------- |  | --------------
|*January 15, 1992  |  | 33-45259 |  | (Form S-3 Registration)             |  | 4(a)(ii)      
|*February 15, 1993 |  | 1-1910   |  | (Form 10-K Annual Report for 1992)  |  | 4(a)(i)       
|*March 1, 1993     |  | 1-1910   |  | (Form 10-K Annual Report for 1992)  |  | 4(a)(ii)      
|*March 15, 1993    |  | 1-1910   |  | (Form 10-K Annual Report for 1992)  |  | 4(a)(iii)     
|*April 15, 1993    |  | 1-1910   |  | (Form 10-Q dated May 13, 1993)      |  | 4             
|*July 1, 1993      |  | 1-1910   |  | (Form 10-Q dated August 13, 1993)   |  | 4(a)          
|*October 15, 1993  |  | 1-1910   |  | (Form 10-Q dated November 12, 1993) |  | 4             
|*June 15, 1996     |  | 1-1910   |  | (Form 10-Q dated August 13, 1996)   |  | 4             

130

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|*4  | (d) |  |  | Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as
of October 1, 1987 (Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
|--- | --- | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|*4  | (e) |  |  | Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures. (Designated as Exhibit 4(d) in Form S-3 dated May 28, 1998,
File No. 333-53767.)                                                                                                                                                                                                                             
|*4  | (f) |  |  | Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures. (Designated as Exhibit 4(e) in Form S-3 dated May 28, 1998,
File No. 333-53767.)                                                                                                                                                                                                                            
|*4  | (g) |  |  | Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) in Form S-3 dated May 28, 1998, File No. 333-53767.)                                                                                                                                                                                                                                                                                                                                                     
|*4  | (h) |  |  | Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) in Form S-3 dated May 28, 1998, File No. 333-53767.)                                                                                                                                                                                                                                                                                                                                                      
|*4  | (i) |  |  | Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) in Form S-3 dated May 28, 1998, File No. 333-53767.)                                                                                                                                                                                                                                                                                                   
|*10 | (a) |  |  | Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated. (Designated as Exhibit No. 10(a) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and
1-1910.)                                                                                                                                                                                                                                       
|*10 | (b) |  |  | Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 2000, File Nos. 1-12869 and
1-1910.)                                                                                                                                                                                                                                            
|10  | (c) |  |  | Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated.                                                                                                                                                                                                                                                                                                                                                                          
|*10 | (d) |  |  | Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(d) to the Annual Report on Form 10-K for the year ended December 31, 2001,
File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                    
|*10 | (e) |  |  | Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(m) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                    
|*10 | (f) |  |  | Summary of severance arrangement for Edward A. Crooke. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                              
|*10 | (g) |  |  | Grantor Trust Agreement Dated as of January 1, 2001 between Constellation Energy Group, Inc. and Citibank, N.A. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 2000, File
Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                     
|10  | (h) |  |  | Form of Severance Agreements between Constellation Energy Group, Inc. and the following named executive officers: Mayo A. Shattuck III, E. Follin Smith, and Frank O. Heintz.                                                                                                                                                                                                                                                                                               
|*10 | (i) |  |  | Grantor Trust Agreement dated as of April 30, 1999 between Constellation Energy Group, Inc. and
T. Rowe Price Trust Company. (Designated as Exhibit No. 10(e) in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                               
|*10 | (j) |  |  | Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 10-Q dated August 14, 2000, File Nos. 1-12869 and 1-1910.)
(Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)                                                                                                                                                     
|*10 | (k) |  |  | Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) in Form 10-Q dated September 30, 2001, File Nos. 1-12869 and
1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)                                                                                                                                                  

131

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|*10 | (l) |  |  | Full Requirements Service Agreement between Baltimore Gas and Electric Company and Allegheny Energy Supply Company, L.L.C. (Designated as Exhibit No. 10(b) in Form 10-Q dated September 30, 2001, File Nos. 1-12869 and
1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)
|--- | --- | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|*10 | (m) |   |  | Constellation Energy Group, Inc. Benefits Restoration Plan, as amended and restated. (Designated as Exhibit No. 10(m) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and
1-1910.)                                                                                                    
|*10 | (n) |  |  | Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated. (Designated as Exhibit No. 10(n) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and
1-1910.)                                                                                                    
|*10 | (o) |  |  | Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated. (Designated as Exhibit No. 10(o) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and
1-1910.)                                                                                           
|*10 | (p) |  |  | Constellation Energy Group, Inc. Supplemental Benefits Plan, as amended and restated. (Designated as Exhibit No. 10(p) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and
1-1910.)                                                                                                   
|10  | (q) |  |  | Compensation agreements between Constellation Energy Group, Inc. and Michael J. Wallace (Attachment 1Employment Agreement; Attachment 2Severance Agreement.)                                                                                                                                                                  
|*10 | (r) |  |  | Compensation agreements between Constellation Energy Group, Inc. and Thomas V. Brooks (Attachment 1Offer letter; Attachment 2Equity letter; Attachment 3Retention plan summary.) (Designated as Exhibit No.
10(r) to the Annual Report on Form 10-K for the year ended December 31, 2001, File
Nos. 1-12869 and 1-1910.)     
|10  | (s) |  |  | Constellation Energy Group, Inc. Executive Long-Term Incentive Plan.                                                                                                                                                                                                                                                            
|*10 | (t) |  |  | Constellation Energy Group, Inc. 2002 Executive Annual Incentive Plan. (Designated as Exhibit No. II in the Definitive Proxy Statement on Schedule 14A filed on April 18, 2002.)                                                                                                                                                
|10  | (u) |  |  | Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan.                                                                                                                                                                                                                                               
|10  | (v) |  |  | Constellation Energy Group, Inc. Management Long-Term Incentive Plan.                                                                                                                                                                                                                                                           
|10  | (w) |  |  | Compensation agreements between Constellation Energy Group, Inc. and E. Follin Smith (Attachment 1. Offer letter; Attachment 2Severance agreement.)                                                                                                                                                                            
|12  | (a) |  |  | Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.                                                                                                                                                                                                                            
|12  | (b) |  |  | Baltimore Gas and Electric Company and Subsidiaries Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend
Requirements.                                                                                                        
|21  |     |  |  | Subsidiaries of the Registrant.                                                                                                                                                                                                                                                                                                 
|23  |     |  |  | Consent of PricewaterhouseCoopers LLP, Independent Accountants.                                                                                                                                                                                                                                                                 

*
Incorporated by Reference.

132

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