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

FORM 10-K


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

For the fiscal year ended DECEMBER 31, 2008

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

1-12869

 

CONSTELLATION ENERGY GROUP, INC.

 

52-1964611
1-1910   BALTIMORE GAS AND ELECTRIC COMPANY   52-0280210

MARYLAND
(States of incorporation)

100 CONSTELLATION WAY,            BALTIMORE, MARYLAND                21202
                                         (Address of principal executive offices)                (Zip Code)

410-470-2800
(Registrants' telephone number, including area code)

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

Title of each class
   
 
Name of each exchange on
which registered
Constellation Energy Group, Inc. Common Stock—Without Par Value   )   New York Stock Exchange
Chicago Stock Exchange

Constellation Energy Group, Inc. Series A Junior Subordinated Debentures
  
6.20% Trust Preferred Securities ($25 liquidation amount per preferred security) issued by BGE Capital Trust II, fully and unconditionally guaranteed, based on several obligations, by Baltimore Gas and Electric Company

 

)

 

New York Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
Not Applicable

        Indicate by check mark if Constellation Energy Group, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý    No o.

        Indicate by check mark if Baltimore Gas and Electric Company is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý    No o.

        Indicate by check mark if Constellation Energy Group, Inc. is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý.

        Indicate by check mark if Baltimore Gas and Electric Company is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý.

        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.    o

        Indicate by check mark whether Constellation Energy Group, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ý        Accelerated filer o        Non-accelerated filer o        Smaller reporting company o

        Indicate by check mark whether Baltimore Gas and Electric Company is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o        Accelerated filer o        Non-accelerated filer ý        Smaller reporting company o

        Indicate by check mark whether Constellation Energy Group, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o    No ý

        Indicate by check mark whether Baltimore Gas and Electric Company is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o    No ý

        Aggregate market value of Constellation Energy Group, Inc. Common Stock, without par value, held by non-affiliates as of June 30, 2008 was approximately $14,585,929,431 based upon New York Stock Exchange composite transaction closing price.

CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE
199,127,544 SHARES OUTSTANDING ON JANUARY 30, 2009.

DOCUMENTS INCORPORATED BY REFERENCE

Part of Form 10-K
 
Document Incorporated by Reference
III   Certain sections of the Proxy Statement for the 2009 Annual Meeting of Shareholders for Constellation Energy Group, Inc.

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




Table of Contents


TABLE OF CONTENTS

 
   
   
  Page  
        Forward Looking Statements     1  
PART I                
  Item 1     Business     2  
                Overview     2  
                Merchant Energy Business     5  
                Baltimore Gas and Electric Company     12  
                Other Nonregulated Businesses     15  
                Consolidated Capital Requirements     16  
                Environmental Matters     16  
                Employees     19  
  Item 1A     Risk Factors     20  
  Item 2     Properties     27  
  Item 3     Legal Proceedings     29  
  Item 4     Submission of Matters to Vote of Security Holders     29  
        Executive Officers of the Registrant (Instruction 3 to Item 401(b) of Regulation S-K)     29  
PART II                
  Item 5     Market for Registrant's Common Equity, Related Shareholder Matters, Issuer Purchases of Equity Securities, and Unregistered Sales of Equity and Use of Proceeds     30  
  Item 6     Selected Financial Data     32  
  Item 7     Management's Discussion and Analysis of Financial Condition and Results of Operations     34  
  Item 7A     Quantitative and Qualitative Disclosures About Market Risk     79  
  Item 8     Financial Statements and Supplementary Data     80  
  Item 9     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     157  
  Item 9A and 9A(T)     Controls and Procedures     157  
  Item 9B     Other Information     157  
PART III                
  Item 10     Directors, Executive Officers and Corporate Governance     157  
  Item 11     Executive Compensation     157  
  Item 12     Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters     157  
  Item 13     Certain Relationships and Related Transactions, and Director Independence     158  
  Item 14     Principal Accountant Fees and Services     158  
PART IV                
  Item 15     Exhibits and Financial Statement Schedules     159  
  Signatures     165  

Table of Contents


Forward Looking Statements

We make statements in this report that are considered forward looking statements within the meaning of the Securities Exchange Act of 1934. Sometimes these statements will contain words such as "believes," "anticipates," "expects," "intends," "plans," and other similar words. We also disclose non-historical information that represents management's expectations, which are based on numerous assumptions. These statements and projections are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance or achievements to be materially different from those we project. These risks, uncertainties, and factors include, but are not limited to:

    the timing and extent of changes in commodity prices and volatilities for energy and energy-related products including coal, natural gas, oil, electricity, nuclear fuel, freight, and emission allowances, and the impact of such changes on our liquidity requirements,
    the liquidity and competitiveness of wholesale markets for energy commodities,
    the conditions of the capital markets, interest rates, foreign exchange rates, availability of credit facilities to support business requirements, liquidity, and general economic conditions, as well as Constellation Energy Group's (Constellation Energy) and Baltimore Gas and Electric's (BGE) ability to maintain their current credit ratings,
    the effectiveness of Constellation Energy's and BGE's risk management policies and procedures and the ability and willingness of our counterparties to satisfy their financial and performance commitments,
    the ability to complete our strategic initiatives to improve our liquidity and the impact of such initiatives on our business and financial results,
    losses on the sale or write-down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets,
    the ability to successfully identify, finance, and complete acquisitions and sales of businesses and assets,
    the likelihood and timing of the completion of the pending transaction with EDF Group and related entities (EDF), the terms and conditions of any required regulatory approvals for the pending transaction, potential impact of a termination of the pending transaction and potential diversion of management's time and attention from our ongoing business during this time period,
    the effect of weather and general economic and business conditions on energy supply, demand, prices, and customers' and counterparties' ability to perform their obligations or make payments,
    the ability to attract and retain customers in our Customer Supply activities and to adequately forecast their energy usage,
    the timing and extent of deregulation of, and competition in, the energy markets, and the rules and regulations adopted in those markets,
    uncertainties associated with estimating natural gas reserves, developing properties, and extracting natural gas,
    regulatory or legislative developments federally, in Maryland, or in other states that affect deregulation, the price of energy, transmission or distribution rates and revenues, demand for energy, or increases in costs, including costs related to nuclear power plants, safety, or environmental compliance,
    the ability of our regulated and nonregulated businesses to comply with complex and/or changing market rules and regulations,
    the ability of BGE to recover all its costs associated with providing customers service,
    operational factors affecting commercial operations of our generating facilities (including nuclear facilities) and BGE's transmission and distribution facilities, including catastrophic weather-related damages, unscheduled outages or repairs, unanticipated changes in fuel costs or availability, unavailability of coal or gas transportation or electric transmission services, workforce issues, terrorism, liabilities associated with catastrophic events, and other events beyond our control,
    the actual outcome of uncertainties associated with assumptions and estimates using judgment when applying critical accounting policies and preparing financial statements, including factors that are estimated in determining the fair value of energy contracts, such as the ability to obtain market prices and, in the absence of verifiable market prices, the appropriateness of models and model inputs (including, but not limited to, estimated contractual load obligations, unit availability, forward commodity prices, interest rates, correlation and volatility factors),
    changes in accounting principles or practices, and
    cost and other effects of legal and administrative proceedings that may not be covered by insurance, including environmental liabilities.

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

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

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PART I

Item 1. Business


Overview

Constellation Energy is an energy company that includes a merchant energy business and BGE, a regulated electric and gas public utility in central Maryland. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "regulated business(es)" are to BGE.

        Our merchant energy business is primarily a competitive provider of energy-related products and services for a variety of customers. It develops, owns, and operates electric generation facilities located in various regions of the United States. Our merchant energy business focuses on serving the energy and capacity requirements (load-serving) of, and providing other energy products and risk management services for, various customers.

        BGE is a regulated electric transmission and distribution utility company and a regulated gas distribution utility company with a service territory that covers the City of Baltimore and all or part of 10 counties in central Maryland. BGE was incorporated in Maryland in 1906.

        Our other nonregulated businesses:

    design, construct, and operate renewable energy, heating, cooling, and cogeneration facilities, and provide various energy-related services, including energy consulting, for commercial, industrial, and governmental customers throughout North America,
    provide home improvements, service heating, air conditioning, plumbing, electrical, and indoor air quality systems, and provide natural gas to residential customers in central Maryland, and
    develop new nuclear plants in North America through our joint venture (UniStar Nuclear Energy, LLC) with a subsidiary of EDF Group.

        As a capital- and asset-intensive business, Constellation Energy was significantly impacted by events in the financial and credit markets during 2008. This has resulted in substantial ongoing changes to our business.

        Over the past few years, our merchant energy business, which includes our trading operations and international commodities operation, grew rapidly. As that business grew, so too did its need for capital, particularly to fund the business' collateral requirements. We had previously met these collateral requirements through the use of cash and lines of credit, and we believed that we could meet any unexpected short-term capital needs by maintaining a significant amount of available liquidity, primarily from our unused credit facilities. Furthermore, by maintaining an investment grade credit rating, we believed we would continue to be able to access the capital markets if additional liquidity needs arose.

        The growth of our merchant energy business and its increased need for collateral, coupled with significant volatility in commodity prices in 2008, required us to post substantial amounts of incremental collateral to our counterparties. The asymmetrical nature of the Customer Supply business' collateral posting requirements compounded the magnitude of the problem, negatively impacting our overall liquidity. We discuss the asymmetrical nature of our collateral in more detail in Item 7. Management's Discussion and Analysis—Collateral section.

        To address these liquidity issues, in 2008, we explored a series of strategic initiatives to improve our liquidity and reduce our business risk. In the first half of 2008, we began to pursue the sale or joint venturing of our highly capital-intensive commodities business based on the concern that our balance sheet could not support the significant growth of this business long-term. We embarked on a process and solicited bids from interested parties and although interest levels were high, following the collapse of Bear Stearns and the significant difficulties encountered by other major financial institutions, we determined we would not get reasonable value for our business. In August 2008, we began efforts to sell our upstream gas properties and our international commodities operation, which includes our coal sourcing, freight, power, natural gas, uranium, and emissions marketing activities outside the United States. In November 2008, we announced we had begun efforts to sell our gas trading operation. We have made progress on many of these initiatives as discussed in more detail in the Divestitures section.

        In September 2008, a rapid and extreme increase in volatility of U.S. and global credit and capital markets caused us to face severe, near-term uncertainty about our ability to maintain sufficient liquidity to continue operating our business. The rating agencies downgraded Constellation Energy's credit ratings because of concerns over our liquidity. The downgrades, in turn, required us to post additional collateral assurance to some of our counterparties, and, since we could not access the capital markets, this further reduced our available liquidity. At that time, we had not made significant progress with our strategic initiatives to generate substantial reductions in our collateral requirements or substantial improvements in our liquidity. As a result, we sought an immediate, substantial investment to ensure our ability to continue operating our business, and in mid-September we ultimately agreed to a transaction with MidAmerican Energy Holdings Company (MidAmerican) that involved an immediate $1 billion preferred equity investment by MidAmerican in us, followed by an all cash sale of our company to MidAmerican for $4.7 billion. In early December 2008, we received an unsolicited offer from EDF Group and related entities

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(EDF) to acquire a membership interest in our nuclear generation and operation business. Our Board of Directors determined the EDF proposal to be in the best interests of our shareholders. Therefore, on December 17, 2008, we and MidAmerican terminated the planned transaction, and we simultaneously entered into a series of transactions with EDF.

        The EDF transactions do not involve the sale of Constellation Energy, but rather the sale of a membership interest in our nuclear generation and operation business resulting in the Company continuing to operate on a standalone basis. The transactions that we agreed to with EDF include the following:

    EDF will purchase from Constellation Energy a 49.99% membership interest in our nuclear generation and operation business for $4.5 billion (subject to certain adjustments) at closing and an additional $150 million of cash received in 2008,
    EDF is providing Constellation Energy with up to $2 billion of additional liquidity pursuant to a put arrangement that will allow us to require EDF to purchase certain non-nuclear generation assets,
    EDF invested $1 billion in Constellation Energy by purchasing 10,000 shares of our 8% Series B Preferred Stock (Series B Preferred Stock). These shares will be surrendered to us when EDF purchases its membership interest in our nuclear generation and operation business, and the $1 billion will be credited against the $4.5 billion purchase price,
    EDF provided us with a $600 million interim backstop liquidity facility, and
    Prior to closing, we will transfer to our nuclear generation and operation business transactions with a negative mark-to-market value not to exceed $700 million in the aggregate using a 10% discount rate. This transfer will occur in a manner that is to be determined and to be mutually acceptable to Constellation Energy and EDF.

        For additional information related to these transactions with MidAmerican and EDF, see Note 15 to Consolidated Financial Statements. For additional information related to the issuance of the Series B Preferred Stock, see Note 9 to Consolidated Financial Statements.

        Over the next one to two years, we expect to be in a transition period during which we will focus on executing the following objectives that we believe will strengthen the Company:

    continuing to implement strategic initiatives to reduce collateral and liquidity needs of our merchant energy business, including selling certain assets and operations as discussed further in the Divestitures section.
    working to close the sale to EDF of 49.99% of our nuclear generation and operation business as expeditiously as possible,
    continuing a disciplined approach to the management of collateral and liquidity, including:
    pricing new business to reflect the full cost of capital in the current economic environment and possibly requiring deposits from new retail customers that do not meet pre-existing credit conditions,
    balancing cash generation with earnings growth, and
    maintaining a liquidity cushion in excess of credit-rating downgrade collateral requirements,
    focusing on Constellation Energy's core strengths of:
    owning, developing, and operating nuclear and non-nuclear generation assets,
    providing reliable, regulated utility service to customers,
    leveraging our expertise in managing physical risks inherent in our Generation and Customer Supply operations, and
    maintaining strong supply relationships with retail and wholesale customers,
    continuing to reduce the scale of and re-focus the activities of our Global Commodities and Customer Supply operations through the following actions:
    using the Global Commodities group to support our Generation and Customer Supply operations,
    placing less reliance on proprietary trading, and
    investing capital in areas where we are able to generate appropriate risk-adjusted returns,
    maintaining credit metrics consistent with investment grade ratings.

        We believe that focusing on the near-term execution of the above objectives will allow us to preserve the flexibility to respond to long-term opportunities. For a further discussion of the above matters and how they have impacted us and our strategy, please refer to Item 7. Management's Discussion and Analysis.

Divestitures

In 2009, we made progress on many of the strategic initiatives we identified in 2008 to improve liquidity and reduce our business risk. These initiatives included selling our international commodities operation, which primarily includes our coal sourcing, freight, power, natural gas, uranium, and emissions marketing activities; our gas trading operation; and our upstream gas properties.

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        In January 2009, we entered into a definitive agreement to sell a majority of our international commodities operation. In February 2009, we entered into a definitive agreement to sell our Houston-based gas trading operation. Simultaneously, we signed a letter of intent to enter into a related transaction with an affiliate of the buyer under which that company would provide us with the gas supply needed to support our retail gas customer supply business, while reducing our credit requirements. We expect that both of these sales will close by the end of the second quarter of 2009, subject to certain regulatory approvals and other standard closing conditions. Upon closing of these transactions, we expect to recognize an aggregate pre-tax loss of not more than $200 million based on current commodity prices. The actual amount of the loss will be affected by the final consideration exchanged, which is based on the timing of the close, and by changes in commodity prices. The impact on cash is not expected to be material.

        Collectively, we expect both divestitures to return to us approximately $1 billion of currently posted collateral. In addition, we expect these divestitures to further reduce our downgrade collateral requirements by approximately $400 million. These reductions are based on current commodity prices, the final terms of the transactions, and the timing of collateral to be returned up to the close of the transactions, and, as a result, are subject to change. We discuss our downgrade collateral requirements in Item 7. Management's Discussion and Analysis—Collateral section.

        While we sold certain of our upstream gas properties in 2008, we continue to evaluate the sale of our remaining upstream gas properties while monitoring market conditions for opportunities to obtain appropriate value for these upstream gas properties. Unlike our international commodities operation and our gas trading operation, there are no material collateral needs associated with the remaining properties, minimizing the need to divest these immediately.

Operating Segments

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

 
  Unaffiliated Revenues  
 
  Merchant
Energy
  Regulated
Electric
  Regulated
Gas
  Holding
Company
and Other
Nonregulated
 

2008

    80 %   14 %   5 %   1 %

2007

    83     12     4     1  

2006

    83     11     5     1  

 

 
  Net Income (Loss) (1)  
 
  Merchant
Energy
  Regulated
Electric
  Regulated
Gas
  Holding
Company
and Other
Nonregulated
 

2008

    (103 )%   %   3 %   %

2007

    83     12     3     2  

2006

    77     16     5     2  

 

 
  Total Assets  
 
  Merchant
Energy
  Regulated
Electric
  Regulated
Gas
  Holding
Company
and Other
Nonregulated
 

2008 (2)

    62 %   21 %   6 %   11 %

2007

    73     20     6     1  

2006

    75     17     6     2  
(1)
Excludes income from discontinued operations in 2007 and 2006 as discussed in more detail in Item 8. Financial Statements and Supplementary Data.

(2)
The increase in Holding Company and Other Nonregulated assets is primarily related to approximately $1.6 billion of intercompany receivables from the merchant energy business, primarily related to the allocation of merger termination and Series A Preferred Stock conversion costs to these businesses, and $1.0 billion of restricted cash related to the issuance of Series B Preferred Stock to EDF. These funds are held at the holding company and are restricted for payment of the 14% Senior Notes held by MidAmerican. The 14% Senior Notes were repaid in full in January 2009.

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Merchant Energy Business

Introduction

Our merchant energy business generates and sells power and gas to both regulated and nonregulated wholesale and retail marketers and consumers of energy products, manages all commodity price risk for our nonregulated businesses, enters into structured energy contracts, and trades energy. We conduct these activities across all regions in the United States and internationally.

        Our merchant energy business includes:

    a power generation and development operation that owns, operates, and maintains fossil and renewable generating facilities, and holds interests in qualifying facilities, fuel processing facilities and power projects in the United States,
    a nuclear generation operation that owns, operates, and maintains nuclear generating facilities,
    a customer supply operation that primarily provides energy products and services to meet the load-serving obligations of wholesale and retail customers, including distribution utilities, cooperatives, aggregators, and commercial, industrial and governmental customers, and
    a global commodities operation that manages contractually controlled physical assets, including generation facilities, natural gas properties, international coal sourcing and freight operations; provides risk management services and uranium marketing services; and trades energy and energy-related commodities.

        In 2008, we began pursuing a number of strategic initiatives that will impact our merchant energy business in 2009 and future years. We discuss these strategic initiatives and how they have impacted our merchant energy business segment and our strategy in Item 7. Management's Discussion and Analysis. We also discuss certain asset and operations divestitures in the Divestitures section.

        During 2008, our merchant energy business:

    supplied approximately 26,600 megawatts (MW) of aggregate peak load to distribution utilities, municipalities, and commercial, industrial, and governmental customers,
    provided approximately 407,000 million British Thermal Units (mmBTUs) of natural gas to commercial, industrial, and governmental customers,
    delivered approximately 25.4 million tons of coal to international and domestic third-party customers and to our own fleet, and
    managed 9,136 MW of generation capacity as of December 31.

        We analyze our merchant energy business in terms of Generation, Customer Supply and Global Commodities activities.

    Generation—encompasses all of our generating assets.
    Customer Supply—encompasses our load-serving operation that provides energy products and services to wholesale and retail electric and natural gas customers.
    Global Commodities—encompasses our marketing, risk management, and trading operations, global coal sourcing and logistics services, and upstream and downstream natural gas services.

Generation

We own, operate, and maintain fossil, nuclear, and renewable generating facilities and hold interests in qualifying facilities, and power projects in the United States and Canada totaling 9,136 MW. We also provide operation and maintenance services, including testing and start-up, to owners of electric generating facilities. The output of these plants is managed by our Global Commodities operation and is hedged through a combination of power sales to wholesale and retail market participants. Our merchant energy business meets the load-serving requirements of various contracts using the output from our generating fleet and from purchases in the wholesale market.

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

Nuclear

The output of our nuclear facilities over the past three years is presented in the following table:

 
  Calvert Cliffs   Nine Mile Point   Ginna  
 
  MWH   Capacity
Factor
  MWH *   Capacity
Factor
  MWH   Capacity
Factor
 
 
  (MWH in millions)
 

2008

    14.7     96 %   12.8     94 %   4.7     94 %

2007

    14.3     94     12.3     90     4.9     98  

2006

    13.8     90     12.8     93     4.1     93  
*
represents our proportionate ownership interest

        We sell a significant portion of the output from our Nine Mile Point Nuclear Station (Nine Mile Point) and our R.E. Ginna Nuclear Plant (Ginna) under unit-specific power purchase agreements. We discuss these arrangements on the next page. Our Global Commodities operation manages the remainder of our generation output.

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        In December 2008, we entered into the Investment Agreement with EDF under which EDF will purchase a 49.99% membership interest in our nuclear generation and operation business, which owns our three nuclear facilities. We discuss the Investment Agreement in more detail in Note 15 to Consolidated Financial Statements.

Calvert Cliffs

We own 100% of Calvert Cliffs Unit 1 (873 MW) and Unit 2 (862 MW). Unit 1 entered service in 1974 and is licensed to operate until 2034. Unit 2 entered service in 1976 and is licensed to operate until 2036.

Nine Mile Point

We own 100% of Nine Mile Point Unit 1 (620 MW) and 82% of Unit 2 (933 MW of Unit 2's total 1,138 MW). The remaining interest in Nine Mile Point Unit 2 is owned by the Long Island Power Authority (LIPA). Unit 1 entered service in 1969 and is licensed to operate until 2029. Unit 2 entered service in 1988 and is licensed to operate until 2046.

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

        After termination of the power purchase agreements, a revenue sharing agreement with the former owner of the plant will begin and continue through 2021. Under this agreement, which applies only to our ownership percentage of Unit 2, a predetermined 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 former owners of the plant. The average strike price for the first year of the revenue sharing agreement is $40.75 per MWH. The strike price increases two percent annually beginning in the second year of the revenue sharing agreement. The revenue sharing agreement is unit contingent and is based on the operation of the unit.

        We exclusively operate Unit 2 under an operating agreement with LIPA. LIPA is responsible for 18% of the operating costs (including decommissioning costs) and construction costs of Unit 2 and has representation on the Nine Mile Point Unit 2 management committee, which provides certain oversight and review functions.

Ginna

We own 100% of the Ginna nuclear facility. Ginna consists of a 581 MW reactor that entered service in 1970 and is licensed to operate until 2029. We sell 90% of the plant's output and capacity to the former owner for 10 years ending in 2014 at an average price of $44.00 per MWH under a long-term unit-contingent power purchase agreement. The remaining output is managed by our Global Commodities operation and sold into the wholesale market.

Qualifying Facilities and Power Projects

We hold up to a 50% voting interest in 18 operating energy projects that consist of electric generation (primarily relying on alternative fuel sources), fuel processing, or fuel handling facilities. Sixteen of the electric generation projects are considered qualifying facilities under the Public Utility Regulatory Policies Act of 1978. Each electric generating plant sells its output to a local utility under long-term contracts.

Customer Supply

We are a leading supplier of energy products and services to wholesale and retail electric and natural gas customers.

        In 2008, our wholesale competitive supply operation served approximately 12,500 peak MWs of wholesale full requirements load-serving products. During 2008, our retail competitive supply activities served approximately 14,100 MW of peak load and approximately 407,000 mmBTUs of natural gas.

        Our wholesale customer supply operation structures transactions that serve the full energy and capacity requirements of various customers 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.

        Our retail customer supply operation structures transactions to supply full energy and capacity requirements and provide natural gas, transportation, and other energy products and services to retail, commercial, industrial, and governmental customers. Contracts with these customers generally extend from one to ten years, but some can be longer. To meet our customers' load-serving requirements, our merchant energy business obtains energy from various sources, including:

    our generation assets,
    exchange-traded and bilateral power and natural gas purchase agreements,
    unit contingent power purchases from generation companies,
    tolling contracts with generation companies, which provide us the right, but not the obligation, to purchase power at a price linked to the variable cost of production, including fuel, with terms that generally extend from several months to several years, but can be longer, and
    regional power pools.

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Global Commodities

Our Global Commodities operation manages contractually owned physical assets, including generation facilities, natural gas properties, international coal sourcing and freight operations, provides risk management services and uranium marketing services, and trades energy and energy-related commodities. This operation provides the wholesale risk management function for our Generation and Customer Supply operations, as well as structured products and energy investment activities and includes our merchant energy business' actual hedged positions with third parties.

Structured Products

Our Global Commodities operation uses energy and energy-related commodities and contracts in order to manage our portfolio of energy purchases and sales to customers through structured transactions. Our Global Commodities operation assists customers with customized risk management products in the power, gas, coal, and freight markets (e.g., generation tolls, gas transport and storage, and global coal and freight logistics).

Energy Investments

Our Global Commodities operation has investments in energy assets that primarily include coal sourcing activities, a joint interest in an entity that owns dry bulk cargo vessels and natural gas services. We discuss each of these investments below.

Coal and International Services

We participate in global coal sourcing activities by providing coal and coal-related logistical services for the variable or fixed supply needs of global customers. We own a 50% interest in a shipping joint venture that owns and operates five freight ships for the delivery of coal and other dry bulk freight products. In 2008, we delivered approximately 25.4 million tons of coal to global customers and to our own generation fleet. Additionally, we entered into power, natural gas, freight, uranium marketing, and emissions transactions outside of the United States.

Natural Gas Services

Our Global Commodities operation includes upstream (exploration and production) and downstream (transportation and storage) natural gas operations. Our upstream activities include the acquisition, development, exploration, and exploitation of natural gas properties, as well as an approximately 28.5% interest in Constellation Energy Partners LLC (CEP), a limited liability company that we formed. CEP is principally engaged in the acquisition, development, and exploitation of natural gas properties. Our downstream activities include providing natural gas to various customers, including large utilities, commercial and industrial customers, power generators, wholesale marketers, and retail aggregators.

        In 2008, 2007, and 2006, we acquired working interests in gas producing fields. We discuss these acquisitions in more detail in Note 15 to Consolidated Financial Statements. In 2008, we divested working interests in certain of our gas producing fields. We discuss these divestitures in more in detail in Note 2 to Consolidated Financial Statements.

Portfolio Management and Trading

We trade energy and energy-related contracts and commodities and deploy risk capital in the management of our portfolio. These activities are managed through daily value at risk and stop loss limits and liquidity guidelines, and could have a material impact on our financial results.

        In managing our portfolio, we may terminate, restructure, or acquire contracts. Such transactions are within the normal course of managing our portfolio and may materially impact the timing of our recognition of revenues, fuel and purchased energy expenses, and cash flows.

        We use both derivative and nonderivative contracts in managing our portfolio of energy sales and purchase contracts. Although a substantial portion of our portfolio is hedged, we are able to identify opportunities to deploy risk capital to increase the value of our accrual positions, which we characterize as portfolio management.

        Active portfolio management is intended to allow our merchant energy business to:

    manage and hedge its fixed-price energy purchase and sale commitments,
    provide fixed-price energy commitments to customers and suppliers,
    reduce exposure to the volatility of market prices, and
    hedge fuel requirements at our non-nuclear generation facilities.

        We discuss the impact of our trading activities and value at risk in more detail in Item 7. Management's Discussion and Analysis.

        Our portfolio management and trading activities involve the use of physical commodity inventories and a variety of instruments, including:

    forward contracts (which commit us to purchase or sell energy commodities in the future),
    swap agreements (which require payments to or from counterparties based upon the difference between two prices for a predetermined contractual (notional) quantity),
    option contracts (which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price), and

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

        Through the third quarter of 2008, our portfolio management and trading activities increased due to the significant growth in scale of our customer supply, energy investments, and structured products operations. However, in the fourth quarter of 2008, we began to take steps to reduce the risk and scale of our portfolio management and trading activities. Energy trading activities will be scaled back and will be used primarily to hedge our generation assets and Customer Supply operations. All of these efforts will materially reduce portfolio management and trading activities' contribution to our future operating results.

Fuel Sources

Our power plants use diverse fuel sources. Our fuel mix based on capacity owned at December 31, 2008 and our generation based on actual output by fuel type in 2008 were as follows:

Fuel
  Capacity
Owned
  Generation  

Nuclear

    42 %   63 %

Coal

    30     32  

Natural Gas

    11     1  

Oil

    8      

Renewable and Alternative (1)

    5     4  

Dual (2)

    4      
(1)
Includes solar, geothermal, hydro, waste coal, and biomass.
(2)
Switches between natural gas and oil.

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

Nuclear

The supply of fuel for nuclear generating stations includes the:

    purchase of uranium (concentrates and uranium hexafluoride),
    conversion of uranium concentrates to uranium hexafluoride,
    enrichment of uranium hexafluoride, and
    fabrication of nuclear fuel assemblies.

        We have commitments that provide for sufficient quantities of uranium (concentrates and uranium hexafluoride), enrichment requirements, and the fabrication of fuel assemblies to meet expected requirements for the next several years at our Calvert Cliffs, Nine Mile Point, and Ginna nuclear generating facilities.

        The nuclear fuel markets are competitive, and prices can be volatile; however, we do not anticipate any significant problems in meeting our future supply requirements.

Storage of Spent Nuclear Fuel—Federal Facilities

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

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

        The DOE has stated that it may not meet that obligation until 2020 at the earliest. This delay has required that we undertake additional actions and incur costs to provide on-site fuel storage at our nuclear generating facilities, including the installation of on-site dry fuel storage capacity as described in more detail below.

        In 2004, complaints were filed against the federal government in the United States Court of Federal Claims seeking to recover damages caused by the DOE's failure to meet its contractual obligation to begin disposing of spent nuclear fuel by January 31, 1998. These cases are currently stayed, pending litigation in other related cases.

        In connection with our purchases of Nine Mile Point and Ginna, all of the former owners' rights and obligations related to recovery of damages for DOE's failure to meet its contractual obligations were assigned to us. However, we have an obligation to reimburse the former owner of Ginna for up to $10 million of any recovered damages for such claims.

Storage of Spent Nuclear Fuel—On-Site Facilities

Calvert Cliffs has a license from the NRC to operate an on-site independent spent fuel storage installation that expires in 2012. Sufficient storage capacity exists within the plant and currently installed independent spent fuel

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storage installation modules to be able to contain the full contents of the core until 2015. Efforts are currently under way to renew the independent spent fuel installation license and expand its capacity to accommodate operations through 2034. Nine Mile Point and Ginna are developing independent spent fuel storage installations at each of those facilities, which we expect to be completed in 2012 and 2010, respectively. Nine Mile Point and Ginna have sufficient storage capacity within the plant until the expected completion of the on-site independent spent fuel storage installations.

Cost for Decommissioning Nuclear Facilities

We are obligated to decommission our nuclear power plants after these plants cease operation. Our nuclear decommissioning trust funds and the investment earnings thereon are restricted to meeting the costs of decommissioning the plants in accordance with NRC regulations and relevant state requirements. We develop our decommissioning trust fund strategy based on estimates of the costs to perform the decommissioning and the timing of incurring those costs. When developing our estimates of future fund earnings, we consider our asset allocation investment strategy, rates of return earned historically, and current market conditions.

        Our nuclear decommissioning trust fund assets are as follows:

At December 31, 2008  

Calvert Cliffs

  $ 346.9  

Nine Mile Point

    460.3  

Ginna

    199.1  
   

Total

  $ 1,006.3  
   

        Every two years, the NRC requires us to demonstrate reasonable assurance that funds will be available to decommission the sites. Our next NRC submittal will occur in March 2009. Due to recent declines in the financial markets, the fair value of our trust funds decreased $324.5 million, net of $18.7 million of contributions made to the trusts, during 2008. As a result of this decline, the NRC may require us to provide additional financial assurance for certain of our plants' decommissioning trusts. Previously, we have provided parental guarantees as additional financial assurance, but alternatively, the NRC could require other forms of financial assurance, including letters of credit, surety bonds, or additional cash contributions to the trusts.

        Decommissioning activities are currently projected to be staged through 2083. Any changes in the costs or timing of decommissioning activities, or changes in the fund earnings, could affect the adequacy of the funds to cover the decommissioning of the plants, and if there were to be a shortfall, we would have to provide additional funding.

Calvert Cliffs

When BGE transferred all of its nuclear generating assets to our merchant energy business, it also transferred the funds accumulated to pay for decommissioning Calvert Cliffs. In March 2008, Constellation Energy, BGE, and a Constellation Energy affiliate entered into a settlement agreement with the State of Maryland, the Public Service Commission of Maryland (Maryland PSC), and certain State of Maryland officials. The settlement agreement became effective on June 1, 2008. Pursuant to the terms of the settlement agreement, BGE customers will be relieved of the potential future liability for decommissioning Calvert Cliffs Unit 1 and Unit 2. BGE will continue to collect the $18.7 million annual nuclear decommissioning charge from all electric customers through 2016 and continue to rebate this amount to residential electric customers, as previously required by Maryland Senate Bill 1 which was enacted in June 2006. We discuss the Maryland settlement agreement in more detail in Note 2 to Consolidated Financial Statements.

Nine Mile Point

The sellers of Nine Mile Point transferred a $441.7 million decommissioning trust fund to us at the time of sale. In return, we assumed all liability for the costs to decommission Unit 1 and 82% of the costs to decommission Unit 2.

Ginna

The seller of Ginna transferred $200.8 million in decommissioning funds to us. In return, we assumed all liability for the costs to decommission the unit.

Coal

We purchase the majority of our coal for electric generation 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)
 

Brandon Shores—Units 1 and 2 (combined)

    3,500,000  

C. P. Crane—Units 1 and 2 (combined)

    850,000  

H. A. Wagner—Units 2 and 3 (combined)

    1,100,000  

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        We receive coal deliveries to these facilities by rail and barge. Over the past few years, we expanded our coal sources through a variety of methods, including restructuring our rail contracts, increasing the range of coals we can consume, and finding potential other coal supply sources including limited shipments from various international sources. While we primarily use coal produced from mines located in central and northern Appalachia, we are capable of switching to coal from the Western United States or imported coal to manage our coal supply. The timely delivery of coal together with the maintenance of appropriate levels of inventory is necessary to allow for continued, reliable generation from these facilities.

        As discussed in the Environmental Matters section, our Maryland coal-fired generating facilities must comply with the requirements of the Maryland Healthy Air Act (HAA), which requires reduction of sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury emissions. We are installing emission control equipment at each of our Maryland coal-fired facilities. The new equipment and HAA emission reduction requirements will influence the characteristics of the coals that we burn in the future.

        All of the Conemaugh and Keystone plants' annual coal requirements are purchased by the plant operators from regional suppliers on the open market. The sulfur restrictions on coal are approximately 2.3% for the Keystone plant and approximately 5.3% for the Conemaugh plant. The Keystone owners are installing emission control equipment at Keystone which will result in a sulfur restriction of 5.3%. Although we expected the Keystone and Conemaugh facilities would have to comply with Pennsylvania mercury regulations beginning in 2010, in January 2009, the Pennsylvania Commonwealth Court held that those regulations were invalid based on a February 2008 federal court decision that struck down the Federal Clean Air Mercury Rule (CAMR). The Commonwealth of Pennsylvania has indicated that it may appeal the court's decision. At this time, we cannot predict the ultimate outcome of these proceedings or its effect on our financial results.

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

        The primary fuel source for Panther Creek and Colver generating facilities is waste coal. These facilities meet their annual requirements through existing reserves of mined and processed waste coal and through supply agreements with various terms.

        All of our coal requirements reflect historical generating 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. However, we believe that we will be able to obtain adequate quantities of coal to meet our requirements.

Gas

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

Oil

From 2006 through 2008, our requirements for residual fuel oil (No. 6) amounted to less than 0.5 million barrels of low-sulfur oil per year. Deliveries of residual fuel oil are made from the suppliers' Baltimore Harbor and Philadelphia marine terminals for distribution to the various generating plant locations. Also, based on normal burn practices, we require approximately 8.0 million to 11.0 million gallons of distillates (No. 2 oil and kerosene) annually, but these requirements can vary substantially from year to year depending upon the relationship between energy prices and fuel costs, weather conditions, and operating requirements. Distillates are purchased from the suppliers' Baltimore truck terminals for distribution to the various generating plant locations. We have contracts with various suppliers to purchase oil at spot prices, and for future delivery, to meet our requirements.

Competition

We encounter competition from companies of various sizes, having varying levels of experience, financial and human resources, and differing strategies.

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

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

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        States are considering different types of regulatory initiatives concerning competition in the power and gas industry, which makes a competitive assessment difficult. Many states continue to support or expand retail competition and industry restructuring. Other states that were considering deregulation have slowed their plans or postponed consideration of deregulation. In addition, certain previously restructured states are considering re-regulation of their retail markets. While there is significant activity in this area, we believe there is adequate growth potential in the current deregulated market.

        As the market for commercial, industrial, and governmental energy supply continues to grow, we have experienced increased competition on a regional basis in our retail competitive supply activities. The increase in retail competition and the impact of wholesale power prices compared to the rates charged by local utilities has, in certain circumstances, reduced the margins that we realize from our customers. However, we believe that our experience and expertise in assessing and managing risk and our strong focus on customer service will help us to remain competitive during volatile or otherwise adverse market circumstances.

Merchant Energy Operating Statistics

 
  2008
  2007
  2006
 
   

Gross Margin (In millions)

                   
 

Generation

  $ 1,956   $ 1,700   $ 1,490  
 

Customer Supply

    765     889     764  
 

Global Commodities

    260     654     656  
   

Total Gross Margin

  $ 2,981   $ 3,243   $ 2,910  
   

Generation (In millions)—MWH *

    50.9     51.6     59.1  
   
*
Includes output from gas-fired plants until sale in December 2006.

Operating statistics do not reflect the elimination of intercompany transactions.


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Baltimore Gas and Electric Company

BGE is an electric transmission and distribution utility company and a gas distribution utility company with a service territory that covers the City of Baltimore and all or part of ten counties in central Maryland. BGE is regulated by the Maryland PSC and Federal Energy Regulatory Commission (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.

Electric Business

Electric Competition

Deregulation

Maryland has implemented electric customer choice and competition among electric suppliers. As a result, all customers can choose their electric energy supplier. While BGE does not sell electricity to all customers in its service territory, BGE continues to deliver electricity to all customers and provides meter reading, billing, emergency response, and regular maintenance.

Standard Offer Service

BGE is obligated to provide market-based standard offer service (SOS) to all of its electric customers who elect not to select a competitive energy supplier. The SOS rates charged recover BGE's wholesale power supply costs and include an administrative fee. The administrative fee includes a shareholder return component and an incremental cost component. As discussed in Item 7. Management's Discussion and Analysis—Regulated Electric Business section, BGE resumed collection of the shareholder return portion of the residential SOS administrative charge, which had been eliminated under Maryland Senate Bill 1, from June 1, 2008 through May 31, 2010 without having to rebate it to all residential electric customers. BGE will cease collecting the residential shareholder return component again from June 1, 2010 through December 31, 2016.

        Bidding to supply BGE's SOS occurs from time to time through a competitive bidding process approved by the Maryland PSC. Successful bidders, which may include subsidiaries of Constellation Energy, execute contracts with BGE for varying terms.

Commercial and Industrial Customers

BGE is obligated to provide several variations of SOS to commercial and industrial customers depending on customer load.

        For those commercial and industrial customers for which SOS originally had been scheduled to expire at the end of May 2007, BGE must continue to provide SOS indefinitely on substantially the same terms as under the then existing service, except that wholesale bidding for service to some customers will be conducted more frequently.

        BGE's obligation to provide SOS to its largest commercial and industrial customers expired in 2005. However, BGE continues to provide an hourly priced SOS to those customers.

Residential Customers

As a result of the November 1999 Maryland PSC order regarding the deregulation of electric generation in Maryland, BGE's residential electric base rates were frozen until July 2006. However, Maryland Senate Bill 1, enacted in June 2006, delayed full market rates for some residential customers until June 2007, with the remainder of residential customers going to full market rates in January 2008. Pursuant to a settlement agreement entered into with the State of Maryland, the Maryland PSC, and certain Maryland officials in March 2008, BGE provided residential electric customers approximately $189 million in the form of a one-time $170 per customer rate credit. We discuss the Maryland settlement agreement in more detail in Note 2 to Consolidated Financial Statements and the market risk of our regulated electric business in more detail in Item 7. Management' Discussion and Analysis—Risk Management section.

Electric Load Management

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

    two options for commercial and industrial customers to reduce their electric loads,
    air conditioning and heat pump control for residential and commercial customers through both programmable thermostats and load control devices, and
    residential water heater control.

        These programs generally take effect on summer days when demand and/or wholesale prices are relatively high and had the effect of reducing BGE's system peak load by 236 MW during the summer period in 2008.

        BGE is developing other programs designed to help manage its peak demand, improve system reliability and improve service to customers by giving customers greater control over their energy use.

        BGE has concluded an advanced metering pilot program and is utilizing the results to develop a strategy for full deployment of the advanced metering program. BGE is also continuing a pilot program to evaluate pricing options designed to incentivize customers to

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decrease energy use during peak demand periods. Additionally, in 2007, BGE initiated a limited conservation program that provides incentives to customers to use energy efficient products and to take other actions to conserve energy. The Maryland PSC recently approved a full portfolio of conservation programs for implementation in 2009 as well as a customer surcharge to recover the associated costs. We also discuss the demand response initiatives in Item 7. Management's Discussion and Analysis—Regulation—Maryland—Maryland PSC section.

Transmission and Distribution Facilities

BGE maintains approximately 250 substations and approximately 1,300 circuit miles of transmission lines throughout central Maryland. BGE also maintains approximately 24,500 circuit miles of distribution lines. The transmission facilities are connected to those of neighboring utility systems as part of PJM Interconnection (PJM). 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 various FERC initiatives relating to wholesale electric markets in more detail in Item 7. Management's Discussion and Analysis—Federal Regulation section.

Electric Operating Statistics

 
  2008
  2007
  2006
 
   

Revenues (In millions)

                   
 

Residential

  $ 1,695.9   $ 1,514.9   $ 1,092.1  
 

Commercial

                   
   

Excluding Delivery Service Only

    604.0     577.4     733.4  
   

Delivery Service Only

    222.8     217.0     149.4  
 

Industrial

                   
   

Excluding Delivery Service Only

    31.3     31.6     46.8  
   

Delivery Service Only

    27.1     27.8     26.2  
   
 

System Sales and Deliveries

    2,581.1     2,368.7     2,047.9  
 

Other (A)

    98.6     87.0     68.0  
   
 

Total

  $ 2,679.7   $ 2,455.7   $ 2,115.9  
   

Distribution Volumes (In thousands)—MWH

                   
 

Residential

    13,023     13,365     12,886  
 

Commercial

                   
   

Excluding Delivery Service Only

    3,957     4,364     6,325  
   

Delivery Service Only

    11,739     11,921     9,392  
 

Industrial

                   
   

Excluding Delivery Service Only

    242     287     467  
   

Delivery Service Only

    3,002     3,175     2,988  
   
 

Total

    31,963     33,112     32,058  
   

Customers (In thousands)

                   
 

Residential

    1,108.5     1,103.1     1,093.3  
 

Commercial

    117.6     116.7     115.5  
 

Industrial

    5.3     5.5     5.2  
   
 

Total

    1,231.4     1,225.3     1,214.0  
   
(A)
Primarily includes network integration transmission service revenues, late payment charges, miscellaneous service fees, and tower leasing revenues.

Operating statistics do not reflect the elimination of intercompany transactions.
"Delivery service only" refers to BGE's delivery of electricity that was purchased by the customer from an alternate supplier.

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Gas Business

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

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

        Approximately 50% of the gas delivered on BGE's distribution system is for customers that purchase gas from alternative suppliers. These customers are charged fees to recover the costs BGE incurs to deliver the customers' gas through our distribution system.

        A market-based rates incentive mechanism applies to customers that buy their gas from BGE. Under this mechanism, BGE's 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 BGE's 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 flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the market-based rates incentive mechanism.

        BGE meets its natural gas load requirements through firm pipeline transportation and storage entitlements.

        BGE's current pipeline firm transportation entitlements to serve its firm loads are 338,053 dekatherms (DTH) per day.

        BGE's current maximum storage entitlements are 254,697 DTH per day. To supplement its gas supply at times of heavy winter demands and to be available in temporary emergencies affecting gas supply, BGE has:

    a liquefied natural gas facility for the liquefaction and storage of natural gas with a total storage capacity of 1,092,977 DTH and a daily capacity of 311,500 DTH, and
    a propane air facility and a mined cavern with a total storage capacity equivalent to 564,200 DTH and a daily capacity of 85,000 DTH.

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

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

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

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Gas Operating Statistics

 
  2008
  2007
  2006
 
   

Revenues (In millions)

                   
 

Residential

                   
   

Excluding Delivery Service Only

  $ 567.8   $ 552.0   $ 490.2  
   

Delivery Service Only

    19.0     19.0     20.6  
 

Commercial

                   
   

Excluding Delivery Service Only

    161.8     154.1     148.9  
   

Delivery Service Only

    46.4     41.2     35.9  
 

Industrial

                   
   

Excluding Delivery Service Only

    8.1     7.8     7.5  
   

Delivery Service Only

    14.5     22.1     19.3  
   
 

System Sales and Deliveries

    817.6     796.2     722.4  
 

Off-System Sales

    197.7     157.4     168.6  
 

Other

    8.7     9.2     8.5  
   
 

Total

  $ 1,024.0   $ 962.8   $ 899.5  
   

Distribution Volumes (In thousands)—DTH

                   
 

Residential

                   
   

Excluding Delivery Service Only

    37,675     39,199     33,019  
   

Delivery Service Only

    4,119     4,310     3,948  
 

Commercial

                   
   

Excluding Delivery Service Only

    12,205     12,464     11,683  
   

Delivery Service Only

    29,289     30,367     25,695  
 

Industrial

                   
   

Excluding Delivery Service Only

    650     658     604  
   

Delivery Service Only

    18,432     17,897     20,325  
   
 

System Sales and Deliveries

    102,370     104,895     95,274  
 

Off-System Sales

    18,782     19,963     19,738  
   
 

Total

    121,152     124,858     115,012  
   

Customers (In thousands)

                   
 

Residential

    605.0     602.3     597.1  
 

Commercial

    42.8     42.7     42.3  
 

Industrial

    1.1     1.2     1.2  
   
 

Total

    648.9     646.2     640.6  
   

Operating statistics do not reflect the elimination of intercompany transactions.
"Delivery service only" refers to BGE's delivery of gas that was purchased by the customer from an alternate supplier.

Franchises

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


Other Nonregulated Businesses

UniStar Nuclear

In 2005, we formed UniStar Nuclear, LLC (UniStar), a joint enterprise with AREVA NP, Inc., (AREVA) to introduce the advanced design Evolutionary Power Reactor to the U.S. market. Upon conversion to U.S. electrical standards, the technology will be known as the U.S. EPR.

        In August 2007, we formed a joint venture, UniStar Nuclear Energy, LLC (UNE) with EDF. We have a 50% ownership interest in this joint venture to develop, own, and operate new nuclear projects in the United States and Canada. EDF initially invested $350 million of cash in UNE, and we contributed our interest in UniStar and other UniStar-related assets, which had a book value of $49 million, and the right to develop new nuclear projects at our existing nuclear plant locations. In the event that the joint venture is terminated, the remaining equity of UNE, after certain expenses, will be divided equally between Constellation Energy and EDF pursuant to the joint venture agreement.

        In 2008, EDF contributed an additional $175 million to UNE based upon reaching certain licensing milestones. EDF will contribute up to an additional $100 million to UNE, for a total of $625 million, upon reaching additional licensing

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milestones after which future funding will be made on a pro rata basis. In 2008, we contributed additional assets which had a book value of $2 million.

        In connection with this joint venture, in 2007 we entered into an investor agreement with EDF under which EDF is limited to owning no more than 9.9% of our outstanding common stock until July 2012 and is required to vote any shares of our common stock owned by it in the manner recommended by our Board of Directors and not take any actions that seek control of Constellation Energy until July 2012. In connection with the execution of the Investment Agreement in December 2008, the investor agreement was amended to enable EDF, in connection with certain extraordinary events, such as a change in control transaction, to acquire shares of our common stock above the 9.9% limitation and to vote its shares at its discretion. The amended investor agreement also provides that following EDF's acquisition of 49.99% of our nuclear generation and operation business, EDF will have the right to appoint one director to our Board of Directors. As of December 31, 2008, EDF owned approximately 8.5% of our outstanding common stock.

Energy Projects and Services

We offer energy projects and services to large commercial, industrial and governmental customers. These energy products and services include:

    designing, constructing, and operating renewable energy, heating, cooling, and cogeneration facilities,
    water and energy savings projects and performance contracting,
    energy consulting and procurement services,
    services to enhance the reliability of individual electric supply systems, and
    customized financing alternatives.

Home Products and Gas Retail Marketing

We offer services to customers in Maryland including:

    home improvements,
    the service of heating, air conditioning, plumbing, electrical, and indoor air quality systems, and
    the sale of natural gas to residential customers.


Consolidated Capital Requirements

Our total capital requirements for 2008 were $2.2 billion. Of this amount, $1.7 billion was used in our nonregulated businesses and $0.5 billion was used in our regulated business. We estimate our total capital requirements will be $1.7 billion in 2009.

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


Environmental Matters

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 development 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, protection of natural and cultural resources, and chemical and waste handling and disposal.

        We continuously monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance. Our capital expenditures were approximately $750 million during the five-year period 2004-2008 to comply with existing environmental standards and regulations. Our estimated environmental capital requirements for the next three years are approximately $330 million in 2009, $50 million in 2010, and $25 million in 2011.

Air Quality

Federal

The Clean Air Act created the basic framework for the federal and state regulation of air pollution.

National Ambient Air Quality Standards (NAAQS)

The NAAQS are federal air quality standards authorized under the Clean Air Act that establish maximum ambient air concentrations for the following specific pollutants: ozone (smog), carbon monoxide, lead, particulates, SO2, and nitrogen dioxides.

        In order for states to achieve compliance with the NAAQS, the Environmental Protection Agency (EPA) adopted the Clean Air Interstate Rule (CAIR) in March 2005 to further reduce ozone and fine particulate pollution by addressing the interstate transport of SO2 and NOx emissions from fossil fuel-fired generating facilities located primarily in the Eastern United States.

        In December 2008, the United States Court of Appeals for the District of Columbia Circuit reversed its July 2008 decision to effectively repeal CAIR and remanded the issue to the EPA for reconsideration. As a result, the requirements of CAIR remain in effect until the EPA takes further action. We cannot predict what additional judicial, legislative or regulatory actions will be taken in response to the court's decision or the EPA's reconsideration of CAIR or whether such actions may affect our financial results. We do not believe that the repeal of CAIR would result in a material change to our emissions reduction plan in Maryland as the emissions reduction requirements of Maryland's HAA and Clean

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Power Rule (CPR) are more stringent and apply sooner than those under CAIR. However, future changes in CAIR could affect the market prices of SO2 and NOx emission allowances, which could in turn affect our financial results. We discuss the impact that these rulings had on our 2008 results in Item 7. Management's Discussion and Analysis—Merchant Energy Business section. We discuss these rulings in more detail in the Note 12 to Consolidated Financial Statements.

        In March 2008, the EPA adopted a stricter NAAQS for ozone. We are unable to determine the impact that complying with the stricter NAAQS for ozone will have on our financial results until the states in which our generating facilities are located adopt plans to meet the new standards.

        In December 2006, the United States Court of Appeals for the District of Columbia Circuit ruled that a requirement to impose fees on emissions sources based on the previous ozone standard (Section 185 fees), which had been rescinded by the EPA in May 2005, remained applicable retroactive to November 2005 and remanded the issue to the EPA for reconsideration. A petition to the United States Supreme Court to hear an appeal was denied in January 2008. The EPA has announced that it intends to propose regulations to address how Section 185 fees will be handled. In addition, the exact method of computing these fees has not been established and will depend in part on state implementation regulations that have not been proposed. Consequently, we are unable to estimate the ultimate financial impact of this matter in light of the uncertainty surrounding the anticipated EPA and state rulemakings. However, the final resolution of this matter, and any fees that are ultimately assessed could have a material impact on our financial results.

        In September 2006, the EPA adopted a stricter NAAQS for particulate matter. We are unable to determine the impact that complying with the stricter NAAQS for particulate matter will have on our financial results until the states in which our generating facilities are located adopt plans to meet the new standard.

Hazardous Air Emissions

In March 2005, the EPA finalized the CAMR to reduce the emissions of mercury from coal-fired facilities through a market-based cap and trade program. CAMR was to affect all coal or waste coal fired boilers at our generating facilities. However, in February 2008, the United States Court of Appeals for the District of Columbia Circuit struck down CAMR. In response to this decision, the EPA recently announced that it intends to develop new mercury emission standards under the CAA. Any new standards that require the installation of additional emissions control technology beyond what is required under Maryland's Healthy Air Act and Clean Power Rule, which are discussed below, may require us to incur additional costs, which could have a material effect on our financial results.

New Source Review

In connection with its enforcement of the CAA's new source review requirements, in 2000, the EPA requested information relating to modifications made to our Brandon Shores, Crane, and Wagner plants located in Maryland. The EPA also sent similar, but narrower, information requests to two of our newer Pennsylvania waste-coal burning plants in which we have an ownership interest. We responded to the EPA in 2001, and as of the date of this report the EPA has taken no further action.

        As discussed in Note 12 to Consolidated Financial Statements, in January 2009, the EPA issued a Notice of Violation to one of our subsidiaries alleging that the Keystone plant located in Pennsylvania, of which we own a 21% interest, performed various capital projects without complying with the new source review requirements.

        Based on the level of emissions control that the EPA and states are seeking in 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.

State

Maryland has adopted the HAA and the CPR, which establish annual SO2, NOx, and mercury emission caps for specific coal-fired units in Maryland, including units located at three of our facilities. The requirements of the HAA and the CPR for SO2, NOx, and mercury emissions are more stringent and apply sooner than those required under CAIR. In addition, Pennsylvania had adopted regulations requiring coal-fired generating facilities located in Pennsylvania to reduce mercury emissions. As we discuss in the Coal section, a Pennsylvania court held that those regulations were invalid in January 2009.

        Several other states in the northeastern U.S. continue to consider more stringent and earlier SO2, NOx, and mercury emissions reductions than those required under CAIR or CAMR.

        Maryland also is in the process of considering changes to its current opacity regulations consistent with its commitment to resolve long-standing industry concerns about the regulations' continuous compliance requirements. However, we are not yet able to determine the final form these revised regulations will take or the impact such revised regulations could have on our business or financial results.

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Capital Expenditure Estimates—Air Quality

We expect to incur additional environmental capital spending as a result of complying with the air quality laws and regulations discussed above. To comply with HAA and CPR, we will install additional air emission control equipment at our coal-fired generating facilities in Maryland and at our co-owned coal-fired facilities in Pennsylvania to meet air quality standards. We include in our estimated environmental capital requirements capital spending for these air quality projects, which we expect will be approximately $295 million in 2009, $40 million in 2010, $15 million in 2011 and $30 million from 2012-2013.

        Our estimates are subject to significant uncertainties including the timing of any additional federal and/or state regulations or legislation, such as any regulations adopted by the EPA in response to the court decision striking down CAMR, the implementation timetables for such regulation or legislation, and the specific amount of emissions reductions that will be required at our facilities. As a result, we cannot predict our capital spending or the scope or timing of these projects with certainty, and the actual expenditures, scope, and timing could differ significantly from our estimates.

        We believe that the additional air emission control equipment we plan to install will meet the emission reduction requirements under HAA and CPR. If additional emission reductions still are required, we will assess our various compliance alternatives and their related costs, and although we cannot yet estimate the additional costs we may incur, such costs could be material.

Global Climate Change

Although uncertainty remains as to the nature and timing of greenhouse gas emissions regulation, there is an increasing likelihood that such regulation will occur at the federal and/or state level. In the event that greenhouse gas emissions reduction legislation or regulations are enacted, we will assess our various compliance alternatives, which may include installation of additional environmental controls, modification of operating schedules, or the closure of one or more of our coal-fired generating facilities. Any compliance costs we incur could have a material impact on our financial results.

        However, to the extent greenhouse gas emissions are regulated through a federal, mandatory cap and trade greenhouse gas emissions program, we believe our business could also benefit. Our generation fleet currently has a carbon dioxide (CO2) emission rate lower than the industry average with more than 60% of the fleet's output coming from low CO2 emitting nuclear and hydroelectric plants. Our global commodities operation has experience trading in the markets for emissions allowances and renewable energy credits.

        In accordance with HAA requirements, Maryland became a full participant in the Northeast Regional Greenhouse Gas Initiative (RGGI) in April 2007. Under RGGI, the Maryland Department of the Environment auctions 100% of CO2 allowances associated with Maryland's power plants, which include plants owned by us. Auctions occurred in September and December 2008. Although we did not incur material costs in these auctions, we could incur material costs in the future to purchase CO2 allowances necessary to offset emissions from our plants.

        In addition, California has adopted regulations requiring our generating facilities in California to submit greenhouse gas emissions data to the state, which the state intends to use to develop a plan to reduce greenhouse gas emissions.

        We continue to evaluate the potential impact of the HAA and California CO2 emissions requirements and RGGI participation on our financial results, however, our compliance costs could be material.

Water Quality

The Clean Water Act established the basic framework for federal and state regulation of water pollution control and requires facilities that discharge waste or storm water into the waters of the United States to obtain permits.

Water Intake Regulations

The Clean Water Act requires cooling water intake structures to reflect the best technology available for minimizing adverse environmental impacts. In July 2004, the EPA published final rules under the Clean Water Act for existing facilities that establish performance standards for meeting the best technology available for minimizing adverse environmental impacts. We currently have seven facilities affected by the regulation. In January 2007, the United States Court of Appeals for the Second Circuit ruled that the EPA's rule did not properly implement the Clean Water Act requirements in a number of areas and remanded the rule to the EPA for reconsideration.

        In response to this ruling, in July 2007, the EPA suspended the second phase of the regulations pending further rulemaking and directed the permitting authorities to establish controls for cooling water intake structures that reflect the best technology available for minimizing adverse environmental impacts. In December 2008, the United States Supreme Court heard an appeal of the Second Circuit's decision relating to the application of cost-benefit analysis to best technology available decisions and a decision is expected in 2009.

        In addition, the EPA is expected to propose new regulations, but the timing of those regulations is uncertain. We will evaluate our compliance options in light of the Supreme Court and Second Circuit

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decisions, the EPA's July 2007 order and any subsequent EPA proposals. At this time, we cannot estimate our compliance costs, but they could be material.

Hazardous and Solid Waste

We discuss proceedings relating to compliance with the Comprehensive Environmental Response, Compensation and Liability Act in Note 12 to Consolidated Financial Statements.

        Our coal-fired generating facilities produce approximately two and a half million tons of combustion by-products ("ash") each year. The EPA announced in 2007 its intention to develop national standards to regulate this material as a non-hazardous waste, and has been developing or considering regulations governing the placement of ash in landfills, surface impoundments, sand/gravel surface mines and coal mines. In addition, the Maryland Department of the Environment finalized regulations governing the disposal, storage, use and placement of ash in December 2008. Federal regulation has the potential to result in additional requirements. Depending on the scope of any final federal requirements, our compliance costs could be material.

        As a result of these regulatory proposals and our current ash generation projections, we are exploring our options for the management of ash, including construction of an ash placement facility. Over the next five years, we estimate that our capital expenditures for this project will be approximately $60 million. Our estimates are subject to significant uncertainties, including the timing of any regulatory change, its implementation timetable, and the scope of the final requirements. As a result, we cannot predict our capital spending or the scope and timing of this project with certainty, and the actual expenditures, scope and timing could differ significantly from our estimates.


Employees

In December 2008, we announced a global workforce reduction of approximately 8%. We completed a portion of this reduction in 2008 with the remainder expected to occur in 2009 in connection with our efforts to sell our upstream gas properties and finalize the sale of a majority of our international commodities operation and our gas trading operation.

        Constellation Energy and its subsidiaries had approximately 10,200 employees at December 31, 2008. At the Nine Mile Point facility, approximately 500 employees are represented by the International Brotherhood of Electrical Workers, Local 97. The labor contract with this union expires in June 2011. We believe that our relationship with this union is satisfactory, but there can be no assurances that this will continue to be the case.

Available Information

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 SEC maintains a website (sec.gov), where copies of our filings may be obtained free of charge. The website address for BGE is bge.com. These website addresses are inactive textual references, and the contents of these websites are not part of this Form 10-K.

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

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

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Item 1A. Risk Factors

You should consider carefully the following risks, along with the other information contained in this Form 10-K. The risks and uncertainties described below are not the only ones that may affect us. Additional risks and uncertainties also may adversely affect our business and operations including those discussed in Item 7. Management's Discussion and Analysis. If any of the following events actually occur, our business and financial results could be materially adversely affected.

Economic conditions and instability in the financial markets could negatively impact our business.

Our operations are affected by local, national, and worldwide economic conditions. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, an increase in customers' inability to pay their accounts, and lower commodity prices. These impacts may adversely affect our financial results and future growth.

        Instability in the financial markets, as a result of recession or otherwise, may affect the cost of capital and our ability to raise capital. We rely on the capital markets, as well as the banking and commercial paper markets to the extent available, to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use letters of credit issued under our credit facilities to support our operations. Disruptions in the capital and credit markets as a result of uncertainty, reduced alternatives, or failures of significant financial institutions could adversely affect our access to liquidity needed for our businesses, including our ability to secure credit facilities and refinance debt that comes due, and our ability to complete other alternatives we are exploring. In addition, such disruptions could adversely affect our ability to draw on our credit facilities. Our access to funds under those credit facilities is dependent on the ability of the banks that are parties to the facilities to meet their funding commitments. Those banks may not be able to meet their funding commitments to us if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from borrowers within a short period of time. The disruptions in capital and credit markets may also result in higher interest rates on publicly issued debt securities and increased costs associated with commercial paper borrowing and under bank credit facilities.

        Any disruptions could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures, further changing our strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash. The inability to obtain the liquidity needed to meet our business requirements, or to obtain such liquidity on terms that are favorable to us, would have a material adverse effect on our business, results of operations and financial condition. If entities with which we do business are unable to raise capital or access the credit markets, they may be unable to perform their obligations or make payments under agreements we have with them. Defaults by these entities may have an adverse effect on our financial results.

We may be unable to execute our strategies to improve liquidity and reduce invested capital.

In an effort to improve our liquidity and reduce our business risk, we are undertaking a number of strategic initiatives to reduce capital spending and ongoing expenses, scale down the expected variability in long-term earnings and short-term collateral usage, and limit our exposure to business activities that require contingent capital support. In connection with these efforts, we have entered into agreements to sell the majority of our international commodities operation and our gas trading operation and we have signed a letter of intent to enter into a gas supply arrangement to support our retail gas activities. While we have entered into these agreements, they remain subject to regulatory approval and other standard closing conditions and we cannot provide any assurance that these sales or other sales will be completed.

        In addition, if we cannot execute on our strategic initiatives successfully, including completing the sales of our international commodities operation and our gas trading operation, our liquidity will be adversely affected, which would have a material adverse effect on our business, results of operations, and financial condition.

A downgrade in our credit ratings could negatively affect our ability to access capital and/or operate our wholesale and retail competitive supply businesses.

We rely on access to capital markets as a source of liquidity for capital requirements not satisfied by operating cash flows. If any of our credit ratings were to be downgraded, especially below investment grade, our ability to raise capital on favorable terms, including in the commercial paper markets, if available, could be hindered, and our borrowing costs would increase. Additionally, the business prospects of our wholesale and retail competitive supply businesses, which in many cases rely on the creditworthiness of Constellation Energy, would be negatively impacted. In this regard, we have certain agreements that contain provisions that would require us to post additional collateral upon a credit rating downgrade. Based on market conditions and contractual obligations at the time of a downgrade, we could be required to post collateral in an amount that exceeds our available liquidity. Also, a credit rating downgrade would

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require us to grant a lien on certain of our generation assets and pledge our ownership interest in our nuclear generation business to the lenders under our credit facilities following the closing or termination of our investment agreement with EDF. Some of the factors that affect credit ratings are cash flows, liquidity, the amount of debt as a component of total capitalization, and political, legislative, and regulatory events. Also, failure to complete our sales of the majority of our international commodities operation and our gas trading operation could result in a credit rating downgrade.

Changes in the prices of commodities and initial margin requirements impact our liquidity requirements.

As a result of the nature of our business, we are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, uranium, and other commodities. We seek to mitigate the effect of these fluctuations through various hedging strategies, which may require the posting of collateral by both us and our counterparties. Changes in the prices of commodities and initial margin requirements for exchange-traded contracts can affect the amount of collateral that must be posted, depending on the particular position we hold. There are certain asymmetries relating to the use of collateral that create liquidity requirements for our merchant energy business. These asymmetries arise as a result of our actions to be economically hedged as well as market conditions or conventions for conducting business that result in some transactions being collateralized while others are not. As a result, significant changes in the prices of commodities and margin requirements for exchange-traded contracts could require us to post additional collateral from time to time without our counterparties having to post collateral to us, which could adversely affect our overall liquidity and ability to finance our operations, which, in turn, could adversely affect our credit ratings.

Our merchant energy business may incur substantial costs and liabilities and be exposed to price volatility and counterparty performance risk as a result of its participation in the wholesale energy markets.

We purchase and sell power and fuel in markets exposed to significant risks, including price volatility for electricity and fuel and the credit risks of counterparties with which we enter into contracts.

        We use various hedging strategies in an effort to mitigate many of these risks. However, hedging transactions do not guard against all risks and are not always effective, as they are based upon predictions about future market conditions. The inability or failure to effectively hedge assets or fuel or power positions against changes in commodity prices, interest rates, counterparty credit risk or other risk measures could significantly impair future financial results.

        Exposure to electricity price volatility.    We buy and sell electricity in both the wholesale bilateral markets and spot markets, which expose us to the risks of rising and falling prices in those markets, and our cash flows may vary accordingly. At any given time, the wholesale spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. This is highly dependent on the regional generation market. In many cases, the next unit of electricity supplied would be supplied from generating stations fueled by fossil fuels, primarily coal, natural gas and oil. Consequently, the open market wholesale price of electricity may reflect the cost of coal, natural gas or oil plus the cost to convert the fuel to electricity and an appropriate return on capital. Therefore, changes in the supply and cost of coal, natural gas and oil may impact the open market wholesale price of electricity.

        A portion of our power generation facilities operates wholly or partially without long-term power purchase agreements. As a result, power from these facilities is sold on the spot market or on a short-term contractual basis, which if not fully hedged may affect the volatility of our financial results.

        Exposure to fuel cost volatility.    Currently, our power generation facilities purchase a portion of their fuel through short-term contracts or on the spot market. Fuel prices can be volatile, and the price that can be obtained for power produced from such fuel may not change at the same rate as fuel costs. As a result, fuel price changes may adversely affect our financial results.

        Exposure to counterparty performance.    Our merchant energy business enters into transactions with numerous third parties (commonly referred to as "counterparties"). In these arrangements, we are exposed to the credit risks of our counterparties and the risk that one or more counterparties may fail to perform under their obligations to make payments or deliver fuel or power. In addition, we enter into various wholesale transactions through Independent System Operators (ISOs). These ISOs are exposed to counterparty credit risks. Any losses relating to counterparty defaults impacting the ISOs are allocated to and borne by all other market participants in the ISO. These risks are exacerbated during periods of commodity price fluctuations. 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 derivative contracts recorded at fair value, the amount owed for settled transactions, and additional payments, if any, that we would have to make to settle unrealized losses on accrual contracts. Defaults by suppliers and other counterparties may adversely affect our financial results.

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Reduced liquidity in the markets in which we operate could impair our ability to appropriately manage the risks of our operations.

We are an active participant in energy markets through our competitive energy businesses. The liquidity of regional energy markets is an important factor in our ability to manage risks in these operations. Over the past several years, other market participants in the merchant energy business have ended or significantly reduced their activities as a result of several factors, including government investigations, changes in market design, and deteriorating credit quality. As a result, several regional energy markets experienced a significant decline in liquidity, which, in turn, has impacted our ability to enter into certain types of transactions to manage our risks for settlement periods beyond 18 to 24 months. Liquidity in the energy markets can be adversely affected by various factors, including price volatility and the availability of credit. As a result, future reductions in liquidity may restrict our ability to manage our risks and this could impact our financial results.

We often rely on single suppliers and at times on single customers, exposing us to significant financial risks if either should fail to perform their obligations.

We often rely on a single supplier for the provision of fuel, water, and other services required for operation of a facility, and at times, we rely on a single customer or a few customers to purchase all or a significant portion of a facility's output, in some cases under long-term agreements that provide the support for any project debt used to finance the facility. The failure of any one customer or supplier to fulfill its contractual obligations could negatively impact our financial results. Consequently, our financial performance depends on the continued performance by customers and suppliers of their obligations under these agreements.

We may not fully hedge our generation assets, customer supply activities, or other market positions against changes in commodity prices, and our hedging procedures may not work as planned.

To lower our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge a portion of our purchase and sale commitments, weather positions, fuel requirements, inventories of natural gas, coal and other commodities, and competitive supply obligations. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, we may not cover the entire exposure of our assets or positions to market price volatility, and the coverage will vary over time. Fluctuating commodity prices may negatively impact our financial results to the extent we have unhedged positions.

        In addition, risk management tools and metrics such as daily value at risk, economic value at risk, stop loss limits and liquidity guidelines are based on historical price movements. If price movements significantly or persistently deviate from historical behavior, the limits may not protect us from significant losses.

        Our risk management policies and procedures may not always work as planned. As a result of these and other factors, we cannot predict with precision the impact that risk management decisions may have on our financial results.

The use of derivative contracts in the normal course of business could result in financial losses that negatively impact our financial results.

We use derivative instruments such as swaps, options, futures and forwards to manage our commodity and financial market risks and to engage in trading activities. We could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform.

        In the absence of actively quoted market prices and pricing information from external sources, the valuation of these derivative instruments involves management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

        Additionally, the settlement of these derivative instruments could reflect a realized value that differs from our estimates of fair value.

Poor market performance will affect our benefit plan and nuclear decommissioning trust asset values, which may adversely affect our liquidity and financial results.

At December 31, 2008, our qualified pension obligations were approximately $835 million greater than the fair value of our plan assets. The Pension Protection Act requires that we fully fund our obligations by 2015. The performance of the capital markets will affect the value of the assets that are held in trust to satisfy our future obligations under our qualified pension plans. A decline in the market value of those assets or the failure of those assets to earn an adequate return may increase our funding requirements for these obligations, which may adversely affect our liquidity and financial results.

        We are required to maintain funded trusts to satisfy our future obligations to decommission our nuclear power plants. A decline in the market value of those assets due to poor investment performance or other factors may increase our funding requirements for these obligations, which may have an adverse effect on our liquidity and financial results.

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The operation of power generation facilities, including nuclear facilities, involves significant risks that could adversely affect our financial results.

We own and operate a number of power generation facilities. The operation of power generation facilities involves many risks, including start-up risks, breakdown or failure of equipment, transmission lines, substations or pipelines, use of new technology, the dependence on a specific fuel source, including the transportation of fuel, or the impact of unusual or adverse weather conditions (including natural disasters such as hurricanes) or environmental compliance, as well as the risk of performance below expected or contracted levels of output or efficiency. This could result in lost revenues and/or increased expenses. Insurance, warranties, or performance guarantees may not cover any or all of the lost revenues or increased expenses, including the cost of replacement power. A portion of our generation facilities were constructed many years ago. Older generating equipment may require significant capital expenditures to keep it operating at peak efficiency. This equipment is also likely to require periodic upgrading and improvement. Breakdown or failure of one of our operating facilities may prevent the facility from performing under applicable power sales agreements which, in certain situations, could result in termination of the agreement or incurring a liability for liquidated damages.

Our generation business may incur substantial costs and liabilities due to its ownership and operation of nuclear generating facilities.

We own and operate nuclear power plants. Ownership and operation of these plants exposes us to risks in addition to those that result from owning and operating non-nuclear power generation facilities. These risks include normal operating risks for a nuclear facility and the risks of a nuclear accident.

        Nuclear Operating Risks.    The ownership and operation of nuclear generating facilities involve routine operating risks, including:

    mechanical or structural problems;
    inadequacy or lapses in maintenance protocols;
    impairment of reactor operation and safety systems due to human or mechanical error;
    costs of storage, handling and disposal of nuclear materials, including the availability or unavailability of a permanent repository for spent nuclear fuel;
    regulatory actions, including shut down of units because of public safety concerns, whether at our plants or other nuclear operators;
    limitations on the amounts and types of insurance coverage commercially available;
    uncertainties regarding both technological and financial aspects of decommissioning nuclear generating facilities; and
    environmental risks, including risks associated with changes in environmental legal requirements.

        Nuclear Accident Risks.    In the event of a nuclear accident, the cost of property damage and other expenses incurred may exceed our insurance coverage available from both private sources and an industry retrospective payment plan. In addition, in the event of an accident at one of our or another participating insured party's nuclear plants, we could be assessed retrospective insurance premiums (because all nuclear plant operators contribute to a nationwide catastrophic insurance fund). Uninsured losses or the payment of retrospective insurance premiums could each have a material adverse effect on our financial results.

Our generation investment plans may not achieve the desired financial results.

We may expand our generation capacity over the next several years through increasing the generating power of existing plants, the renovation of retired plants owned by us, and the construction or acquisition of new plants. The renovation, development, construction, and acquisition of additional generation capacity involves numerous risks. Any planned power uprates, construction, or renovation could result in cost overruns, lower than expected plant efficiency, and higher operating and other costs. With respect to the renovation of retired plants or the construction of new plants, we may incur significant sums for preliminary engineering, permitting, legal, and other expenses before it can be established whether a project is feasible, economically attractive, or capable of being financed.

        If we were unable to complete the construction or renovation of a plant, we may not be able to recover our investment in the project. Furthermore, we may be unable to run any new, acquired or renovated plants as efficiently as projected, which could result in higher-than-projected operating and other costs that adversely affect our financial results.

We are subject to numerous environmental laws and regulations that require capital expenditures, increase our cost of operations and may expose us to environmental liabilities.

We are subject to extensive federal, state, and local environmental statutes, rules, and regulations relating to air quality, water quality, waste management, wildlife protection, the management of natural resources, and the protection of human health and safety that could, among other things, require additional pollution control equipment, limit the use of certain fuels, restrict the output of certain facilities, or otherwise increase costs. Significant capital expenditures, operating and other costs are associated with compliance with environmental requirements, and these expenditures and costs could become even more significant in the future as a result of regulatory changes.

        For example, there is increasing likelihood that additional regulation of greenhouse gas emissions will

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occur at the federal, regional, and/or state level, which could increase our compliance and operating costs.

        We are subject to liability under environmental laws for the costs of remediating environmental contamination. Remediation activities include the cleanup of current facilities and former properties, including manufactured gas plant operations and offsite waste disposal facilities. The remediation costs could be significantly higher than the liabilities recorded by us. Also, our subsidiaries are currently involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future.

        We are subject to legal proceedings by individuals alleging injury from exposure to hazardous substances and could incur liabilities that may be material to our financial results. Additional proceedings could be filed against us in the future.

        We may also be required to assume environmental liabilities in connection with future acquisitions. As a result, we may be liable for significant environmental remediation costs and other liabilities arising from the operation of acquired facilities, which may adversely affect our financial results.

We, and BGE in particular, are subject to extensive local, state and federal regulation that could affect our operations and costs.

We are subject to regulation by federal and state governmental entities, including the FERC, the NRC, the Maryland PSC and the utility commissions of other states in which we have operations. In addition, changing governmental policies and regulatory actions can have a significant impact on us. Regulations can affect, for example, allowed rates of return, requirements for plant operations, recovery of costs, limitations on dividend payments, and the regulation or re-regulation of wholesale and retail competition (including, but not limited to, retail choice and transmission costs).

        BGE's distribution rates are subject to regulation by the Maryland PSC, and such rates are effective until new rates are approved. If the Maryland PSC does not approve adequate new rates, BGE might not be able to recover certain costs it incurs or earn an adequate rate of return. In addition, limited categories of costs are recovered through adjustment charges that are periodically reset to reflect current and projected costs. Inability to recover material costs not included in rates or adjustment clauses, including increases in uncollectible customer accounts that may result from higher gas and electric costs, could have an adverse effect on our, or BGE's, cash flow and financial position.

        Energy legislation enacted in Maryland in June 2006 and April 2007 mandated that the Maryland PSC review Maryland's deregulated electricity market. Although the settlement agreement reached with the State of Maryland in March 2008 terminated certain studies relating to the 1999 deregulation settlement, the State of Maryland, including the Maryland legislature, and the Maryland PSC are still undertaking a review of the Maryland electric industry and market structure to consider various options for providing standard offer service to residential customers, including re-regulation. We cannot at this time predict the final outcome of this review or how such outcome may affect our, or BGE's financial results, but it could be material.

        The regulatory and legislative process may restrict our ability to grow earnings in certain parts of our business, cause delays in or affect business planning and transactions and increase our, or BGE's, costs.

We operate in deregulated segments of the electric and gas industries created by federal and state restructuring initiatives. If competitive restructuring of the electric or gas industries is reversed, discontinued, restricted, or delayed, our business prospects and financial results could be materially adversely affected.

The regulatory environment applicable to the electric and natural gas industries has undergone substantial changes as a result of restructuring initiatives at both the state and federal levels. These initiatives have had a significant impact on the nature of the electric and natural gas industries and the manner in which their participants conduct their businesses. We have targeted the competitive segments of the electric and natural gas industries created by these initiatives.

        Due to recent events in the energy markets, energy companies have been under increased scrutiny by state legislatures, regulatory bodies, capital markets, and credit rating agencies. This increased scrutiny could lead to substantial changes in laws and regulations affecting us, including modifications to the auction processes in competitive markets and new accounting standards that could change the way we are required to record revenues, expenses, assets, and liabilities. Recent proposals by the Maryland PSC and certain members of the Maryland legislature, relating to the structure of the electric industry in Maryland and various options for re-regulation of the industry are examples of how these laws and regulations can change. We cannot predict the future development of regulation or legislation in these markets or the ultimate effect that this changing regulatory environment will have on our business.

        If competitive restructuring of the electric and natural gas markets is reversed, discontinued, restricted, or delayed, or if the recent Maryland PSC or legislative proposals are implemented in a manner adverse to us, our business prospects and financial results could be negatively impacted.

Our financial results may be harmed if transportation and transmission availability is limited or unreliable.

We have business operations throughout the United States and internationally. As a result, we depend on transportation and transmission facilities owned and operated by utilities and other energy companies to deliver the electricity, coal, and natural gas we sell to

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the wholesale and retail markets, as well as the natural gas and coal we purchase to supply some of our generating facilities. If transportation or transmission is disrupted or capacity is inadequate, our ability to sell and deliver products may be hindered. Such disruptions could also hinder our ability to provide electricity, coal, or natural gas to our customers or power plants and may materially adversely affect our financial results.

Our merchant energy business has contractual obligations to certain customers to provide full requirements service, which makes it difficult to predict and plan for load requirements and may result in increased operating costs to our business.

Our merchant energy business has contractual obligations to certain customers to supply full requirements service to such customers to satisfy all or a portion of their energy requirements. The uncertainty regarding the amount of load that our merchant energy business must be prepared to supply to customers may increase our operating costs. A significant under- or over-estimation of load requirements could result in our merchant energy business not having enough power or having too much power to cover its load obligation, in which case it would be required to buy or sell power from or to third parties at prevailing market prices. Those prices may not be favorable and thus could increase our operating costs and result in the possibility of reduced earnings or incurring losses.

Our financial results may fluctuate on a seasonal and quarterly basis or as a result of severe weather.

Our business is affected by weather conditions. Our overall operating results may fluctuate substantially on a seasonal basis, and the pattern of this fluctuation may change depending on the nature and location of any facility we acquire and the terms of any contract to which we become a party. Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities.

        Generally, demand for electricity peaks in winter and summer and demand for gas peaks in the winter. Typically, when winters are warmer than expected and summers are cooler than expected, demand for energy is lower, resulting in less electric and gas consumption than forecasted. Depending on prevailing market prices for electricity and gas, these and other unexpected conditions may reduce our revenues and results of operations. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and may make period comparisons less relevant.

        Severe weather can be destructive, causing outages and/or property damage. This could require us to incur additional costs. Catastrophic weather, such as hurricanes, could impact our or our customers' operating facilities, communication systems and technology. Unfavorable weather conditions may have a material adverse effect on our financial results.

A failure in our operational systems or infrastructure, or those of third parties, may adversely affect our financial results.

Our businesses are dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, accounting, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws or employee tampering or manipulation of those systems will result in losses that are difficult to detect.

        We may also be subject to disruptions of our operational systems arising from events that are wholly or partially beyond our control (for example, natural disasters, acts of terrorism, epidemics, computer viruses and telecommunications outages). Third party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt one or more of our businesses, result in potential liability or reputational damage or otherwise have an adverse affect on our financial results.

Our ability to successfully identify, complete and integrate acquisitions is subject to significant risks, including the effect of increased competition.

We are likely to encounter significant competition for acquisition opportunities that may become available. In addition, we may be unable to identify attractive acquisition opportunities at favorable prices, to secure the financing necessary to undertake them, or to successfully and timely complete and integrate them.

War and threats of terrorism and catastrophic events that could result from terrorism may impact our results of operations in unpredictable ways.

We cannot predict the impact that any future terrorist attacks may have on the energy industry in general and on our business in particular. In addition, any retaliatory military strikes or sustained military campaign may affect our operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. The possibility alone that infrastructure facilities, such as electric generation, electric and gas transmission and distribution facilities would be direct targets of, or indirect casualties of, an act of terror may affect our operations.

        Such activity may have an adverse effect on the United States economy in general. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our financial results or restrict our future growth. Instability in the

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financial markets as a result of terrorism or war may affect our stock price and our ability to raise capital.

We are subject to employee workforce factors that could affect our businesses and financial results.

We are subject to employee workforce factors, including loss or retirement of key executives or other employees, availability of qualified personnel, collective bargaining agreements with union employees, and work stoppage that could affect our financial results. In particular, our competitive energy businesses are dependent, in part, on recruiting and retaining personnel with experience in sophisticated energy transactions and the functioning of complex wholesale markets.

Our transaction with EDF is subject to closing conditions, including regulatory approvals, that, if not satisfied or waived by the appropriate party, will result in the transaction not being completed, which may result in material adverse consequences to our business and operations.

On December 17, 2008, we announced the execution of an investment agreement with EDF relating to the acquisition by EDF of a 49.99% ownership interest in our nuclear generation and operation business. The transaction is subject to closing conditions, including the receipt of consents, orders, approvals, or clearances from various federal, state and international regulatory agencies, that, if not satisfied, will prevent the transaction from being completed. In addition, if the agreement is terminated by EDF as a result of our breach of the agreement, the put arrangement between us and EDF that provides us with additional liquidity of up to $2.0 billion would also terminate.

        As part of the regulatory approval process, governmental entities may impose terms and conditions that may not be acceptable to us or EDF, which may give either party the right to terminate the investment agreement. Also, governmental entities may impose terms and conditions that are unfavorable or add significant additional costs to our future operations whether the transaction is completed or not. A substantial delay in obtaining required approvals or the imposition of unfavorable terms or conditions in connection with such approvals could have a material adverse effect on our business or financial results and could also have a negative impact on our credit ratings. In addition, delays or unfavorable terms could lead us to become involved in litigation with one or more governmental entities or private litigants or may cause us or EDF to terminate the investment agreement.

If the investment agreement with EDF is terminated we will be required to issue senior notes to EDF.

If the investment agreement with EDF is terminated the Series B Preferred Stock acquired by EDF will be redeemed on the later of the date of termination of the agreement or December 31, 2009 for $1.0 billion in aggregate principal amount of 10% Senior Notes. The 10% Senior Notes to be issued upon redemption of the Series B Preferred Stock will mature on June 30, 2010. This obligation will reduce the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business. The redemption of the Series B Preferred Stock could also have a negative impact on our credit ratings.

If the investment agreement with EDF is terminated and the 10% Senior Notes are issued by us upon redemption of the Series B Preferred Stock, the 10% Senior Notes will contain restrictions on the operation of our business.

The 10% Senior Notes to be issued upon redemption of our Series B Preferred Stock contain various covenants that will limit our ability to engage in specific types of transactions and in operating our business. Constellation Energy and certain of its subsidiaries will be subject to negative covenants that will be consistent with those included in Constellation Energy's credit facilities, which include limitations on indebtedness; incurring certain liens; engaging in certain fundamental changes; the sale of its assets; certain types of restricted payments; investments, loans and advances; acquisitions and transactions with affiliates; optional payments and modifications to debt instruments; and the issuance of capital stock.

The sale of non-nuclear generation plants pursuant to the put arrangement with EDF may have an adverse effect on our financial results.

We have entered into a put arrangement with EDF that, subject to regulatory approval, provides us with additional liquidity of up to $2.0 billion by allowing us to exercise an option to require EDF to acquire certain specified non-nuclear generation plants at pre-agreed prices. To the extent we exercise this option, we will no longer own the plants sold to EDF and will not be able to recognize their financial results, which may have an adverse effect on our future financial results.

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Item 2. Properties

Constellation Energy occupies approximately 970,000 square feet of leased and owned office space in North America, which includes its corporate offices in Baltimore, Maryland. We describe our electric generation properties on the next page. We also have leases for other offices and services located in the Baltimore metropolitan region, and for various real property and facilities relating to our generation projects.

        BGE owns its principal headquarters building located in downtown Baltimore. BGE also leases approximately 50,000 square feet of office space. In addition, BGE owns propane air and liquefied natural gas facilities as discussed in Item 1. Business—Gas Business section.

        BGE also has rights-of-way to maintain 26-inch natural gas mains across certain Baltimore City-owned property (principally parks) which expired in 2004. BGE is in the process of renewing the rights-of-way with Baltimore City for an additional 25 years. The expiration of the rights-of-way does not affect BGE's ability to use the rights-of-way during the renewal process.

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

    in public streets and highways pursuant to franchises, and
    on rights-of-way secured for the most part by grants from owners of the property.

        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.

        Our merchant energy business owns several natural gas producing properties. We also lease office space in Australia, Canada, Indonesia, Japan and the United Kingdom to support our merchant energy business.

27


        The following table describes our generating facilities:

Plant
  Location
  Capacity
(MW)

  %
Owned

  Capacity Owned
(MW)

  Primary
Fuel

 

Calvert Cliffs Unit 1 (1)

  Calvert Co., MD     873     100.0     873  

Nuclear

Calvert Cliffs Unit 2 (1)

  Calvert Co., MD     862     100.0     862  

Nuclear

Nine Mile Point Unit 1 (1)

  Scriba, NY     620     100.0     620  

Nuclear

Nine Mile Point Unit 2 (1)

  Scriba, NY     1,138     82.0     933  

Nuclear

R.E. Ginna (1)

  Ontario, NY     581     100.0     581  

Nuclear

Brandon Shores

  Anne Arundel Co., MD     1,286     100.0     1,286  

Coal

H. A. Wagner

  Anne Arundel Co., MD     995     100.0     995  

Coal/Oil/Gas

C. P. Crane (2)

  Baltimore Co., MD     399     100.0     399  

Oil/Coal

Keystone (2)

  Armstrong and Indiana Cos., PA     1,711     21.0     359 (4)

Coal

Conemaugh (2)

  Indiana Co., PA     1,711     10.6     181 (4)

Coal

Perryman (2)

  Harford Co., MD     355     100.0     355  

Oil/Gas

Riverside

  Baltimore Co., MD     228     100.0     228  

Oil/Gas

Handsome Lake (2)

  Rockland Twp, PA     268     100.0     268  

Gas

Notch Cliff

  Baltimore Co., MD     120     100.0     120  

Gas

Westport

  Baltimore City, MD     121     100.0     121  

Gas

Gould Street

  Baltimore City, MD     97     100.0     97  

Gas

Philadelphia Road

  Baltimore City, MD     64     100.0     64  

Oil

Safe Harbor (2)

  Safe Harbor, PA     417     66.7     278  

Hydro

Grande Prairie (2)

  Calgary, Alberta, Canada     85     100.00     85  

Gas

West Valley (2)

  West Valley, UT     200     100.00     200  

Gas

Panther Creek (2)

  Nesquehoning, PA     80     50.0     40  

Waste Coal

Colver (2)

  Colver Township, PA     104     25.0     26  

Waste Coal

Sunnyside (2)

  Sunnyside, UT     51     50.0     26  

Waste Coal

ACE (2)

  Trona, CA     102     31.1     32  

Coal

Jasmin

  Kern Co., CA     35     50.0     18  

Coal

POSO

  Kern Co., CA     35     50.0     18  

Coal

Mammoth Lakes G-1

  Mammoth Lakes, CA     6     50.0     3  

Geothermal

Mammoth Lakes G-2

  Mammoth Lakes, CA     13     50.0     7  

Geothermal

Mammoth Lakes G-3

  Mammoth Lakes, CA     13     50.0     7  

Geothermal

Rocklin

  Placer Co., CA     24     50.0     12  

Biomass

Fresno

  Fresno, CA     24     50.0     12  

Biomass

Chinese Station

  Jamestown, CA     20     45.0     9  

Biomass

Malacha

  Muck Valley, CA     32     50.0     16  

Hydro

SEGS IV

  Kramer Junction, CA     33     12.2     4  

Solar

SEGS V

  Kramer Junction, CA     24     4.2     1  

Solar

SEGS VI

  Kramer Junction, CA     34     8.8     3  

Solar

                       

Total Generating Facilities (3)

        12,761           9,136    
                       
(1)
In December 2008, we entered into an Investment Agreement with EDF under which EDF would acquire a 49.99% interest in our subsidiary that holds these nuclear generation assets. We discuss the Investment Agreement in more detail in Note 15 to Consolidated Financial Statements.
(2)
In connection with the Investment Agreement with EDF, we have the option to sell one or more of these facilities to EDF for aggregate proceeds of up to $2 billion through the earlier of December 31, 2010 or the termination of the Investment Agreement by EDF due to our breach.
(3)
The sum of the individual plant capacity megawatts may not equal the total due to the effects of rounding.
(4)
Reflects our proportionate interest in and entitlement to capacity from Keystone and Conemaugh, which include 2 MW of diesel capacity for Keystone and 1 MW of diesel capacity for Conemaugh.

In February 2008, we acquired the Hillabee Energy Center, a partially completed 774 MW gas-fired combined cycle power generation facility located in Alabama. We plan to complete the construction of this facility and expect it to be ready for commercial operation in late 2009.

As of December 31, 2008, we also have a 50% ownership interest in a waste coal processing facility located in Hazelton, Pennsylvania.

28


Item 3. Legal Proceedings

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

Item 4. Submission of Matters to Vote of Security Holders

Not applicable.


Executive Officers of the Registrant

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

Mayo A. Shattuck III

  54   Chairman of the Board (since July 2002), President and Chief Executive Officer (since November 2001) of Constellation Energy   Chairman of the Board of Baltimore Gas and Electric Company

Michael J. Wallace

 

61

 

Vice Chairman of Constellation Energy (since March 2008)

 

President and Chief Executive Officer—Constellation Energy Nuclear Group, LLC and Executive Vice President—Constellation Energy

Henry B. Barron

 

58

 

Executive Vice President of Constellation Energy (since April 2008); and President, Chief Executive Officer and Chief Nuclear Officer (since September 2008) of Constellation Energy Nuclear Group

 

Group Executive and Chief Nuclear Officer—Duke Energy

Thomas F. Brady

 

59

 

Executive Vice President of Constellation Energy (since January 2004); and Chairman of the Board of Baltimore Gas and Electric Company (since April 2007)

 

None

James L. Connaughton

 

47

 

Executive Vice President, Corporate Affairs, Public, and Environmental Policy (since February 2009)

 

Chairman of the White House Council on Environmental Quality and Director of the White House Office of Environmental Policy

Paul J. Allen

 

57

 

Senior Vice President (since January 2004) and Chief Environmental Officer (since June 2007) of Constellation Energy

 

Vice President, Corporate Affairs—Constellation Energy

Charles A. Berardesco

 

50

 

Senior Vice President (since October 2008), General Counsel (since October 2008) and Corporate Secretary (since July 2004) of Constellation Energy

 

Vice President and Deputy General Counsel—Constellation Energy; and Associate General Counsel—Constellation Energy

Brenda L. Boultwood

 

44

 

Senior Vice President and Chief Risk Officer of Constellation Energy (since January 2008)

 

Global Head of Strategy, Alternative Investment Services—J.P. Morgan Chase & Company

Kenneth W. DeFontes, Jr.

 

58

 

Senior Vice President of Constellation Energy (since October 2004); and President and Chief Executive Officer of Baltimore Gas and Electric Company (since October 2004)

 

Vice President, Electric Transmission and Distribution—Baltimore Gas and Electric Company

Kathleen W. Hyle

 

50

 

Senior Vice President of Constellation Energy (since September 2005); and Chief Operating Officer of Constellation Energy Resources (since November 2008)

 

Senior Vice President, Finance, and Chief Financial Officer—Constellation Energy Nuclear Group; Chief Financial Officer—UniStar Nuclear Energy; Senior Vice President, Finance—Constellation Energy; and Chief Financial Officer, Constellation NewEnergy

Beth S. Perlman

 

48

 

Senior Vice President (since January 2004), Chief Administrative Officer (since June 2007) and Chief Information Officer (since April 2002) of Constellation Energy

 

None

Jonathan W. Thayer

 

37

 

Senior Vice President and Chief Financial Officer of Constellation Energy (since October 2008)

 

Vice President and Managing Director, Corporate Strategy and Development—Constellation Energy; Treasurer—Constellation Energy; and Senior Vice President and Chief Financial Officer—Baltimore Gas and Electric Company

        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.

29



PART II

Item 5. Market for Registrant's Common Equity, Related Shareholder Matters, Issuer Purchases of Equity Securities, and Unregistered Sales of Equity and Use of Proceeds

Stock Trading

Constellation Energy's common stock is traded under the ticker symbol CEG. It is listed on the New York and Chicago stock exchanges.

        As of January 30, 2009, there were 36,697 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 February 2009, we announced a quarterly dividend of $0.24 per share payable April 1, 2009 to holders of record on March 10, 2009. This is equivalent to an annual rate of $0.96 per share.

        Quarterly dividends were declared on our common stock during 2008 and 2007 in the amounts set forth below.

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

    BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid; or
    any dividends (and any redemption payments) due on BGE's preference stock have not been paid.

Common Stock Dividends and Price Ranges

 
  2008   2007  
 
   
  Price    
  Price  
 
  Dividend
Declared
  Dividend
Declared
 
 
  High   Low   High   Low  

First Quarter

  $ 0.4775   $ 107.97   $ 81.94   $ 0.435   $ 88.20   $ 68.78  

Second Quarter

    0.4775     94.62     78.74     0.435     95.57     82.71  

Third Quarter

    0.4775     85.53     13.00     0.435     98.20     76.64  

Fourth Quarter

    0.4775     30.17     21.70     0.435     104.29     85.81  
                                   

Total

  $ 1.91               $ 1.74              
                                   

30


Purchases of Equity Securities by the Issuer and Affiliated Purchases

The following table discloses purchases of shares of our common stock made by us or on our behalf for the periods shown below.

Period
  Total Number
of Shares
Purchased (1)
  Average Price
Paid for Shares
  Total Number
of Shares
Purchased as
Part of Publicly
Announced
Plans or
Programs
  Maximum Dollar
Amount of Shares
that May Yet Be
Purchased Under
the Plans and Programs
(at month end) (2)
 

October 1 - October 31, 2008

    3,075   $ 23.96       $ 750 million  

November 1 - November 30, 2008

    2,031     24.21         750 million  

December 1 - December 31, 2008

    725     25.01         750 million  
   

Total

    5,831   $ 24.18          
   
(1)
Represents shares surrendered by employees to satisfy tax withholding obligations on vested restricted stock.
(2)
In October 2007, our Board of Directors approved a common share repurchase program for up to $1 billion of our outstanding common shares over the 24 months following approval. Pursuant to the terms of our Series B Preferred Stock, we are prohibited from engaging in a common share repurchase in an aggregate amount in excess of $100 million without the approval of the holders of more than 50% of the then outstanding shares of Series B Preferred Stock.

Unregistered Sales of Equity Securities and Use of Proceeds

The sale and issuance of Constellation Energy's 8% Series A Convertible Preferred Stock to MidAmerican Energy Holdings Company was reported previously on a Current Report on Form 8-K dated September 22, 2008. The sale and issuance of Constellation Energy's 8% Series B Preferred Stock to EDF was reported previously on a Current Report on Form 8-K dated December 17, 2008. We also discuss these issuances in Note 9 to Consolidated Financial Statements.

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Table of Contents

Item 6. Selected Financial Data

Constellation Energy Group, Inc. and Subsidiaries

 
  2008
  2007
  2006
  2005
  2004
 
   
 
  (In millions, except per share amounts)
 

Summary of Operations

                               
 

Total Revenues

  $ 19,818.3   $ 21,193.2   $ 19,284.9   $ 16,968.3   $ 12,127.2  
 

Total Expenses

    20,821.9     19,858.8     18,025.2     16,023.8     11,209.1  
 

Gains on Sales of Assets

    25.5         73.8          
   
 

(Loss) Income From Operations

    (978.1 )   1,334.4     1,333.5     944.5     918.1  
 

Gains on Sales of CEP LLC equity

        63.3     28.7          
 

Other (Expense) Income

    (52.3 )   158.6     66.1     65.5     25.5  
 

Fixed Charges

    362.3     305.6     328.7     310.2     326.8  
   
 

(Loss) Income Before Income Taxes

    (1,392.7 )   1,250.7     1,099.6     699.8     616.8  
 

Income Tax (Benefit) Expense

    (78.3 )   428.3     351.0     163.9     118.4  
   
 

(Loss) Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles

    (1,314.4 )   822.4     748.6     535.9     498.4  
   

(Loss) Income from Discontinued Operations, Net of Income Taxes

        (0.9 )   187.8     94.4     41.3  
   

Cumulative Effects of Changes in Accounting Principles, Net of Income Taxes

                (7.2 )    
   
 

Net (Loss) Income

  $ (1,314.4 ) $ 821.5   $ 936.4   $ 623.1   $ 539.7  
   
 

(Loss) Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles Assuming Dilution

  $ (7.34 ) $ 4.51   $ 4.12   $ 2.98   $ 2.88  
   

(Loss) Income from Discontinued Operations

        (0.01 )   1.04     0.53     0.24  
   

Cumulative Effects of Changes in Accounting Principles

                (0.04 )    
   
 

(Loss) Earnings Per Common Share Assuming Dilution

  $ (7.34 ) $ 4.50   $ 5.16   $ 3.47   $ 3.12  
   
 

Dividends Declared Per Common Share

  $ 1.91   $ 1.74   $ 1.51   $ 1.34   $ 1.14  
   

Summary of Financial Condition

                               
 

Total Assets

  $ 22,284.1   $ 21,742.3   $ 21,801.6   $ 21,473.9   $ 17,347.1  
   
 

Current Portion of Long-Term Debt

  $ 2,591.5   $ 380.6   $ 878.8   $ 491.3   $ 480.4  
   
 

Capitalization

                               
   

Long-Term Debt

  $ 5,098.7   $ 4,660.5   $ 4,222.3   $ 4,369.3   $ 4,813.2  
   

Minority Interests

    20.1     19.2     94.5     22.4     90.9  
   

Preference Stock Not Subject to Mandatory Redemption

    190.0     190.0     190.0     190.0     190.0  
   

Common Shareholders' Equity

    3,181.4     5,340.2     4,609.3     4,915.5     4,726.9  
   
 

Total Capitalization

  $ 8,490.2   $ 10,209.9   $ 9,116.1   $ 9,497.2   $ 9,821.0  
   

Financial Statistics at Year End

                               
 

Ratio of Earnings to Fixed Charges

    N/A     3.84     4.05     3.04     2.71  
 

Book Value Per Share of Common Stock

  $ 15.98   $ 29.93   $ 25.54   $ 27.57   $ 26.81  

N/A—Calculation is not applicable as a result of the net loss for 2008.

We discuss items that affect comparability between years, including acquisitions and dispositions, accounting changes and other items, in Item 7. Management's Discussion and Analysis.

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Baltimore Gas and Electric Company and Subsidiaries

 
  2008
  2007
  2006
  2005
  2004
 
   
 
  (In millions)
 

Summary of Operations

                               
 

Total Revenues

  $ 3,703.7   $ 3,418.5   $ 3,015.4   $ 3,009.3   $ 2,724.7  
 

Total Expenses

    3,521.2     3,084.2     2,646.3     2,612.8     2,353.3  
   
 

Income From Operations

    182.5     334.3     369.1     396.5     371.4  
 

Other Income (Expense)

    29.6     26.8     6.0     5.9     (6.4 )
 

Fixed Charges

    139.9     125.3     102.6     93.5     96.2  
   
 

Income Before Income Taxes

    72.2     235.8     272.5     308.9     268.8  
 

Income Taxes

    20.7     96.0     102.2     119.9     102.5  
   
 

Net Income

    51.5     139.8     170.3     189.0     166.3  
 

Preference Stock Dividends

    13.2     13.2     13.2     13.2     13.2  
   
 

Earnings Applicable to Common Stock

  $ 38.3   $ 126.6   $ 157.1   $ 175.8   $ 153.1  
   

Summary of Financial Condition

                               
 

Total Assets

  $ 6,086.2   $ 5,783.0   $ 5,140.7   $ 4,742.1   $ 4,662.9  
   
 

Current Portion of Long-Term Debt

  $ 90.0   $ 375.0   $ 258.3   $ 469.6   $ 165.9  
   
 

Capitalization

                               
   

Long-Term Debt

  $ 2,197.7   $ 1,862.5   $ 1,480.5   $ 1,015.1   $ 1,359.5  
   

Minority Interest

    16.9     16.8     16.7     18.3     18.7  
   

Preference Stock Not Subject to Mandatory Redemption

    190.0     190.0     190.0     190.0     190.0  
   

Common Shareholder's Equity

    1,538.2     1,671.7     1,651.5     1,622.5     1,566.0  
   
 

Total Capitalization

  $ 3,942.8   $ 3,741.0   $ 3,338.7   $ 2,845.9   $ 3,134.2  
   

Financial Statistics at Year End

                               
 

Ratio of Earnings to Fixed Charges

    1.50     2.84     3.60     4.22     3.75  
 

Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends

    1.33     2.42     2.99     3.45     3.08  

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

Introduction and Overview

Constellation Energy Group, Inc. (Constellation Energy) is an energy company that conducts its business through various subsidiaries including a merchant energy business and Baltimore Gas and Electric Company (BGE). We describe our operating segments in Note 3 to Consolidated Financial Statements.

        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 "regulated business(es)" are to BGE. We discuss our business in more detail in Item 1. Business section and the risk factors affecting our business in Item 1A. Risk Factors section.

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

    factors which affect our businesses,
    our earnings and costs in the periods presented,
    changes in earnings and costs between periods,
    sources of earnings,
    impact of these factors on our overall financial condition,
    expected sources of cash for future capital expenditures,
    our net available liquidity and collateral requirements, and
    expected future expenditures for capital projects.

        As you read this discussion and analysis, refer to our Consolidated Statements of Income (Loss), which present the results of our operations for 2008, 2007, and 2006. We analyze and explain the differences between periods in the specific line items of our Consolidated Statements of Income (Loss).

        We have organized our discussion and analysis as follows:

    First, we discuss our strategy.
    Then, we describe the business environment in which we operate including how recent events, competition, regulation, weather, and other factors affect our business.
    Next, we discuss our critical accounting policies. These are the accounting policies that are most important to both the portrayal of our financial condition and results of operations and require management's most difficult, subjective or complex judgment.
    We highlight significant events that are important to understanding our results of operations and financial condition.
    We review our results of operations beginning with an overview of our total company results, followed by a more detailed review of those results by operating segment.
    We review our financial condition addressing our sources and uses of cash, security ratings, capital resources, capital requirements, commitments, and off-balance sheet arrangements.
    We conclude with a discussion of our exposure to various market risks.

Strategy

We are pursuing a strategy of operating nuclear and non-nuclear generation facilities, providing energy and energy-related products and services through our Customer Supply activities, and delivering electricity and gas to customers of BGE, our regulated utility located in central Maryland. Our merchant energy business focuses on short-term and long-term purchases and sales of energy, capacity, and related products to various customers, including distribution utilities, municipalities, cooperatives, and industrial, commercial, and governmental customers.

        We obtain this energy from both owned and contracted supply resources. Our generation fleet is strategically located in deregulated markets and includes various fuel types, such as nuclear, coal, natural gas, oil, and renewable sources. In addition to owning generating facilities, we contract for power from other merchant providers, typically through power purchase agreements. We use both our owned generation and our contracted generation to support our wholesale and retail Customer Supply operations.

        We are also in the forefront of the proposed development of new nuclear generation in the United States through our UniStar Nuclear Energy joint venture with EDF Group and related entities (EDF). In addition, in December 2008, we entered into an investment agreement with EDF to sell to EDF a 49.99% interest in our nuclear generation and operation business (Investment Agreement). EDF brings operational experience, global scale, and procurement leverage to the development of new nuclear plants in the United States and to the operation of our existing nuclear plants. This new joint venture is expected to close in the third quarter of 2009, subject to receipt of regulatory approvals.

        Collectively, the integration of owned and contracted electric generation assets with origination, fuel procurement, and risk management expertise allows our merchant energy business to earn incremental margin and more effectively manage energy and commodity price risk over geographic regions and time. Our focus is on providing solutions to customers' energy needs, and our Customer Supply and Global Commodities operations add value to our owned and contracted generation assets by providing national market access, market infrastructure, real-time market intelligence, risk management and arbitrage opportunities, and transmission and transportation expertise. Generation capacity supports our Customer Supply and Global Commodities operations by providing a source of reliable power supply.

        We expect BGE and our Customer Supply operation to grow through focused and disciplined expansion. At BGE, we are also focused on enhancing reliability, customer satisfaction, and customer demand response initiatives.

        Customer choice, regulatory change, and energy market conditions significantly impact our business. In response, we regularly evaluate our strategies with these goals in mind: to improve our competitive position, to anticipate and adapt to the business environment and regulatory changes, and to maintain a strong balance sheet and investment-grade credit quality through the use of a financial model that applies cash flow to reduce debt.

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        As a result of the significant events of 2008 as discussed in the Business Environment section, we are actively seeking to increase available liquidity and reduce our business risk. Over the next one to two years, we expect to be in a transition period during which we will focus on executing the following objectives that we believe will strengthen the Company:

    continuing to implement strategic initiatives to reduce collateral and liquidity needs of our merchant energy business, including selling certain assets and operations as discussed further in the Divestitures section in Item 1.
    working to close the sale to EDF of 49.99% of our nuclear generation and operation business as expeditiously as possible,
    continuing a disciplined approach to the management of collateral and liquidity, including:
    pricing new business to reflect the full cost of capital in the current economic environment and possibly requiring deposits from new retail customers that do not meet pre-existing credit conditions,
    balancing cash generation with earnings growth, and
    maintaining a liquidity cushion in excess of credit-rating downgrade collateral requirements,
    focusing on Constellation Energy's core strengths of:
    owning, developing, and operating nuclear and non-nuclear generation assets,
    providing reliable, regulated utility service to customers,
    leveraging our expertise in managing physical risks inherent in our Generation and Customer Supply operations, and
    maintaining strong supply relationships with retail and wholesale customers,
    continuing to reduce the scale of and re-focus the activities of our Global Commodities and Customer Supply operations through the following actions:
    using the Global Commodities group to support our Generation and Customer Supply operations,
    placing less reliance on proprietary trading,
    investing capital in areas where we are able to generate appropriate risk-adjusted returns,
    maintaining credit metrics consistent with investment grade ratings.

        The execution of our strategy in the future will be affected by our ability to achieve these goals as well as by continued instability in financial and commodities markets. Execution of our goals, including the pending asset divestitures, could have a substantial effect on the nature and mix of our business activities, as well as our financial position, results of operation and cash flows.

        In addition, upon closing the transaction contemplated by our Investment Agreement with EDF, we expect to deconsolidate our subsidiary that owns our nuclear generation assets. In turn, this could affect our financial position, results of operations, and cash flows in material amounts, and these amounts could vary substantially from historical results.

Business Environment

Various factors affect our financial results. We discuss some of these factors in more detail in Item 1. Business—Competition section. We also discuss these various factors in the Forward Looking Statements and Item 1A. Risk Factors sections.

        During the last year, two events significantly influenced our business environment: the collapse of the credit markets and the extreme volatility in the energy markets. Throughout 2008, volatility in the financial markets intensified, leading to dramatic declines in equity prices and substantially reducing liquidity in the credit markets. Most equity indices declined significantly, the cost of credit default swaps and bond spreads increased substantially, and credit markets effectively ceased to be accessible for all but the most highly rated borrowers.

        Major financial institutions experienced significant financial difficulty, and widespread fears developed about the viability of any business that required access to credit markets to support liquidity needs or that required substantial access to the capital markets to function, including Constellation Energy. By mid-September 2008, despite having announced a number of actions to address our liquidity situation, we faced a sudden and immediate need to raise equity capital and take other steps to enhance our overall liquidity. As a result, on September 19, 2008, we entered into a definitive merger agreement with MidAmerican Energy Holdings Company (MidAmerican) to acquire Constellation Energy for $4.7 billion, which also provided us with an immediate $1 billion cash infusion. In December 2008, however, we terminated the merger agreement with MidAmerican and entered into an agreement to sell a 49.99% interest in our nuclear generation and operation business for $4.5 billion to EDF. Under that agreement, EDF provided us with a $1 billion cash infusion to replace the investment made by MidAmerican. We repaid MidAmerican's $1 billion plus interest in January 2009. We discuss the termination of the merger with MidAmerican and our transaction with EDF in more detail in Note 15 to Consolidated Financial Statements.

        The volatility of the global energy markets impacts our liquidity and collateral requirements as well as our credit risk. We discuss our liquidity and collateral requirements in the Financial Condition section. We continue to actively manage our credit risk to attempt to reduce the impact of a potential counterparty default. We discuss our customer (counterparty) credit and other risks in more detail in the Risk Management section.

Competition

We face competition in the sale of electricity, natural gas, coal, and uranium in wholesale energy markets and to retail customers.

        Various states have moved to restructure their retail electricity and gas markets. The pace of deregulation in these states varies based on historical moves to competition and responses to recent market events. While many states continue to support or expand retail competition and industry restructuring, other states that were considering deregulation

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have slowed their plans or postponed consideration. In addition, other states are reconsidering deregulation.

        Specifically, legislatures in a number of states are currently considering, to varying degrees, legislation to either eliminate or expand retail choice programs. In addition, many states have initiated proceedings to reconsider the method of wholesale procurement for meeting their utilities' default/provider-of-last-resort (POLR) requirements. Both the reconsideration of retail choice and possible new methodologies for wholesale procurement could affect our Customer Supply operation's future opportunities to service commercial and industrial customers and the ability to provide wholesale products to utilities. The outcome of these efforts cannot be predicted, but they could have a material effect on our financial results.

        All BGE electricity and gas customers have the option to purchase electricity and gas from alternate suppliers.

        We discuss merchant competition in more detail in Item 1. Business—Competition section.

        The impacts of electric deregulation on BGE in Maryland are discussed in Item 1. Business—Baltimore Gas and Electric Company—Electric Business—Electric Competition section.

Regulation—Maryland

Maryland PSC

In addition to electric restructuring, which we discuss in Item 1. Business—Electric Competition section, regulation by the Maryland Public Service Commission (Maryland PSC) significantly influences BGE's businesses. The Maryland PSC determines the rates that BGE can charge customers of its electric distribution and gas businesses. The Maryland PSC incorporates into BGE's standard offer service rates the transmission rates determined by the Federal Energy Regulatory Commission (FERC). BGE's electric rates are unbundled in customer billings to show separate components for delivery service (i.e. base rates), electric supply (commodity charge and transmission), a universal service surcharge, and certain taxes. The rates for BGE's regulated gas business continue to consist of a delivery charge (base rate) and a commodity charge.

Maryland Settlement Agreement

In March 2008, Constellation Energy, BGE, and a Constellation Energy affiliate entered into a settlement agreement with the State of Maryland, the Maryland PSC and certain State of Maryland officials to resolve pending litigation and to settle other prior legal, regulatory, and legislative issues. On April 24, 2008, the Governor of Maryland signed enabling legislation, which became effective on June 1, 2008. Pursuant to the terms of the settlement agreement:

    Each party acknowledged that the agreements adopted in 1999 relating to Maryland's electric restructuring law are final and binding and the Maryland PSC will close ongoing proceedings relating to the 1999 settlement.
    BGE provided its residential electric customers approximately $189 million in the form of a one-time $170 per customer rate credit. We recorded a reduction to "Electric revenues" on our and BGE's Consolidated Statements of Income (Loss) during the second quarter of 2008 and reduced customers' bills by the amount of the credit between September and December 2008.
    BGE customers are relieved of the potential future liability for decommissioning Constellation Energy's Calvert Cliffs Unit 1 and Unit 2, scheduled to occur no earlier than 2034 and 2036, respectively, and are no longer obligated to pay a total of $520 million, in 1993 dollars adjusted for inflation, pursuant to the 1999 Maryland PSC order regarding the deregulation of electric generation. BGE will continue to collect the $18.7 million annual nuclear decommissioning charge from all electric customers through 2016 and continue to rebate this amount to residential electric customers, as previously required by Maryland Senate Bill 1, which was enacted in June 2006.
    BGE resumed collection of the residential return portion of the administrative charge included in Standard Offer Service (SOS) rates, which had been eliminated under Senate Bill 1, on June 1, 2008 and will continue collection through May 31, 2010 without having to rebate it to all residential electric customers. This will total approximately $40 million over this period. This charge will be suspended from June 1, 2010 through December 31, 2016.
    Any electric distribution base rate case filed by BGE will not result in increased distribution rates prior to October 2009, and any increase in electric distribution revenue awarded will be capped at 5% with certain exceptions. Any subsequent electric distribution base rate case may not be filed prior to August 1, 2010. The agreement does not govern or affect our ability to recover costs associated with gas rates, federally approved transmission rates and charges, electric riders, tax increases, or increases associated with standard offer service power supply auctions.
    Effective June 1, 2008, BGE implemented revised depreciation rates for regulatory and financial reporting purposes. The revised rates reduced depreciation expense by approximately $14 million in 2008 without impacting distribution rates charged to customers.
    Effective June 1, 2008, Maryland laws governing investments in companies that own and operate regulated gas and electric utilities were amended to make them less restrictive with respect to certain capital stock acquisition transactions.
    Constellation Energy elected two independent directors to the Board of Directors of BGE within the required six months from the execution of the settlement agreement.

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Senate Bills 1 and 400

In June 2006, Maryland Senate Bill 1 was enacted, which among other things:

    imposed rate stabilization measures that (i) capped rate increases by BGE for residential SOS service at 15% from July 1, 2006 to May 31, 2007, (ii) gave residential SOS customers the option from June 1, 2007 until December 31, 2007 of paying a full market rate or choosing a short term rate stabilization plan in order to provide a smooth transition to market rates without adversely affecting the creditworthiness of BGE, and (iii) provided for full market rates for all residential SOS service starting January 1, 2008; and
    allowed BGE to recover the costs deferred from July 1, 2006 to May 31, 2007 from its customers over a period not to exceed 10 years, on terms and conditions to be determined by the Maryland PSC, including through the issuance of rate stabilization bonds that securitize the deferred costs.

        In connection with these provisions of Senate Bill 1:

    In May 2007, the Maryland PSC approved a plan to allow residential electric customers to defer the transition to full market rates from June 1, 2007 to January 1, 2008. The 4 percent of customers who chose to defer are repaying the deferred amounts without interest over a twenty-one month period which began on April 1, 2008.
    In June 2007, a subsidiary of BGE issued an aggregate principal amount of $623.2 million of rate stabilization bonds to recover costs relating to the residential rate deferral from July 1, 2006 to May 31, 2007. We discuss the rate stabilization bond issuance in more detail in Note 9 to Consolidated Financial Statements.

        In April 2007, Maryland Senate Bill 400 was enacted, which made certain modifications to Senate Bill 1. Pursuant to Senate Bill 400, the Maryland PSC was required to initiate several studies, including studies relating to stranded costs, the costs and benefits of various options for re-regulation, and the structure of the electric industry in Maryland.

        In December 2007, the Maryland PSC issued an interim report addressing the costs and benefits of various options for re-regulation and recommending actions to be taken to address an anticipated shortage of generation and transmission capacity in Maryland, which included implementation of demand response initiatives and requiring utilities to enter into long-term power purchase contracts with suppliers.

        The Maryland PSC issued a final report in December 2008. In the final report, the Maryland PSC does not recommend returning the former utility generation assets to full cost of service regulation, but rather recommends incremental, forward looking re-regulation when appropriate to ensure a reliable supply of electricity or to obtain economic benefits for customers. The report also indicates that the Maryland PSC will investigate in 2009 whether, and on what terms, additional generation should be built in Maryland. In addition, the Maryland legislature continues to review the structure of the Maryland energy markets and the need for re-regulation. We cannot at this time predict the ultimate outcome of these inquiries, studies, and recommendations or their actual effect on our, or BGE's financial results, but it could be material.

        We discuss the market risk of our regulated electric business in more detail in the Risk Management section.

Base Rates

Base rates are the rates the Maryland PSC allows BGE to charge its customers for the cost of providing them delivery service, plus a profit. BGE has both electric base rates and gas base rates.

        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 its utility plant investment and operating costs, plus a profit. Generally, rate increases improve the earnings of our regulated business 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.

        BGE's most recently approved return on electric distribution rate base was 9.4% (approved in 1993). BGE's most recently approved return on gas rate base was 8.49% (approved in 2005).

        According to the terms of the 2008 Maryland settlement agreement, any future electric distribution base rate case filed by BGE will not result in increased distribution rates prior to October 2009, and any increase in electric distribution revenue awarded will be capped at 5% with certain exceptions. Any subsequent electric distribution base rate case may not be filed prior to August 1, 2010. The agreement does not govern or affect our ability to recover costs associated with gas rates, federally approved transmission rates and charges, electric riders, tax increases, or increases associated with standard offer service power supply auctions.

Revenue Decoupling

Beginning in 2008, the Maryland PSC approved, and BGE implemented, revenue decoupling for residential and small commercial customers to eliminate the effect of abnormal weather and usage patterns per customer on its electric distribution volumes. This means that BGE's electric distribution revenues from residential and small commercial customers reflect weather and usage that is considered normal for the month. Therefore, these revenues are affected primarily by customer growth. The Maryland PSC approved revenue decoupling for the majority of our remaining commercial and industrial customers beginning February 1, 2009. We have a similar revenue decoupling mechanism in our gas business.

Demand Response and Advanced Metering Programs

In order to implement an advanced metering pilot program and a demand response program, BGE defers costs associated with these programs as a regulatory asset and recovers these costs from customers in future periods. We discuss the advanced metering and demand response programs in more detail in Item 1. Business—Baltimore Gas and Electric Company—Electric Load Management.

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Electric Commodity and Transmission Charges

We discuss BGE electric commodity and transmission charges (standard offer service), including the impact of the enactment of Senate Bill 1 in Maryland, in the Business Environment—Regulation—Maryland—Senate Bills 1 and 400 section.

Gas Commodity Charge

BGE charges its gas customers separately for the natural gas they purchase. The price BGE charges for the natural gas is based on a market-based rates incentive mechanism approved by the Maryland PSC. We discuss market-based rates in more detail in the Regulated Gas Business—Gas Cost Adjustments section and in Note 6 to Consolidated Financial Statements.

Federal Regulation

FERC

The FERC has jurisdiction over various aspects of our business, including electric transmission and wholesale natural gas and electricity sales. BGE transmission rates are updated annually based on a formula methodology approved by FERC. The rates also include transmission investment incentives approved by FERC in orders issued in July and November of 2007. We believe that FERC's continued commitment to fair and efficient wholesale energy markets should continue to result in improvements to competitive markets across various regions.

        Since 1997, operation of BGE's transmission system has been under the authority of PJM Interconnection (PJM), the Regional Transmission Organization (RTO) for the Mid-Atlantic region, pursuant to FERC oversight. As the transmission operator, PJM administers the energy markets and conducts day-to-day operations of the bulk power system. The liability of transmission owners, including BGE, and power generators is limited to those damages caused by the gross negligence of such entities.

        In addition to PJM, RTOs exist in other regions of the country such as the Midwest, New York, and New England. Similar to PJM, these RTOs also administer the energy market for their region and are responsible for operation of the transmission system and transmission system reliability. Our merchant energy business participates in these regional energy markets. These markets are continuing to develop, and revisions to market structure are subject to review and approval by FERC. We cannot predict the outcome of any reviews at this time. However, changes to the structure of these markets could have a material effect on our financial results.

FERC Initiatives

Ongoing initiatives at FERC have included a review of its methodology for the granting of market-based rate authority to sellers of electricity. FERC has established interim tests that it uses to determine the extent to which companies may have market power in certain regions. Where FERC finds that market power exists, it may require companies to implement measures to mitigate the market power in order to maintain market-based rate authority. We believe that our entities selling wholesale power continue to satisfy FERC's test for determining whether to grant a public utility market-based rate authority.

        In November 2004, FERC eliminated through and out transmission rates between the Midwest Independent System Operator (MISO) and PJM and put in place Seams Elimination Charge/Cost Adjustment/Assignment (SECA) transition rates, which are paid by the transmission customers of MISO and PJM and allocated among the various transmission owners in PJM and MISO. The SECA transition rates were in effect from December 1, 2004 through March 31, 2006. FERC set for hearing the various compliance filings that established the level of the SECA rates and has indicated that the SECA rates are being recovered from the MISO and PJM transmission customers subject to refund by the MISO and PJM transmission owners.

        We are a recipient of SECA payments, payer of SECA charges, and supplier to whom such charges may be shifted. Administrative hearings regarding the SECA charges concluded in May 2006, and an initial decision from the FERC administrative law judge (ALJ) was issued in August 2006. The decision of the ALJ generally found in favor of reducing the overall SECA liability. The decision, if upheld, is expected to significantly reduce the overall SECA liability at issue in this proceeding. However, the ALJ also allowed SECA charges to be shifted to upstream suppliers, subject to certain adjustments. Therefore, certain charges could be shifted to our wholesale marketing, risk management, and trading operation. This decision will be reviewed by FERC. We are unable to predict the timing or final outcome of FERC's SECA rate proceeding. However, as the amounts collected under the SECA rates are subject to refund and the ultimate outcome of the proceeding establishing SECA rates is uncertain, the result of this proceeding may have a material effect on our financial results.

Capacity Markets

In April 2006, FERC issued an initial order approving PJM's proposal to restructure its capacity market, which establishes the method by which we are paid for making generating plant capacity available to PJM. The capacity market or Reliability Pricing Model (RPM) was approved by FERC in December 2006 after settlement proceedings. FERC in June and November 2007 upheld the RPM settlement in response to requests for rehearing. An appeal of FERC's decisions on RPM was filed in January 2008 in the United States Court of Appeals for the District of Columbia Circuit. Currently, we cannot predict with certainty what effect the results of these challenges will have on our, or BGE's, financial results.

        Also in January 2008 in connection with RPM, PJM filed revisions to its capacity market rules to reflect increased construction costs for new entry of generation (CONE), which was rejected by FERC in April 2008. CONE is used in determining the price paid to capacity resources that clear in the PJM capacity auction. In September 2008, FERC directed PJM to consider revisions and improvements to RPM to become effective prior to the May 2009 auction. In December 2008, PJM filed proposed tariff changes to RPM with FERC. PJM proposes significant revisions to RPM, including the determination of CONE, the participation of energy efficiency and demand resources, and market power and mitigation rules.

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We cannot predict the outcome of the FERC proceeding. However, the outcome could have a material effect on our financial results depending on the nature of the resulting changes to RPM.

        In May 2008, five state public service commissions, including the Maryland PSC, consumer advocates, and others filed a complaint against PJM at the FERC, alleging that the RPM produced unreasonable prices during the period from June 1, 2008 through May 31, 2011. The complaint requests that FERC establish a refund effective date of June 1, 2008, reject the results of the 2007/08 through 2010/11 RPM capacity auction results, and significantly reduce prices for capacity beginning as of June 1, 2008 through 2011/12. We, along with other power suppliers and supplier trade groups, have filed protests to the complaint. In September 2008, FERC dismissed the complaint and in October 2008, the complainants requested a rehearing at FERC. We cannot predict the outcome of this proceeding or the amount of refunds that may be owed by or due to us, if any. However, the outcome, and any refunds that are ultimately assessed, could have a material impact on our financial results.

        Three major, high-voltage transmission lines have been announced that could enhance significantly the transfer capacity of the PJM transmission system from west to east. The siting process either in the states or at FERC is uncertain, as is the likelihood that one or more of the transmission lines will be ultimately constructed. The construction of the transmission lines, which could depress both capacity and energy prices for generation located in Maryland and elsewhere in the eastern part of PJM, could have a material effect on our financial results.

        Other market changes are routinely proposed and considered on an ongoing basis. Such changes will be subject to FERC's review and approval. We cannot predict the outcome of these proceedings or the possible effect on our, or BGE's, financial results at this time.

NERC Reliability Standards

In compliance with the Energy Policy Act of 2005, FERC has approved the North American Electric Reliability Corporation (NERC) as the national energy reliability organization. NERC will be responsible for the development and enforcement of mandatory reliability standards for the wholesale electric power system. We are responsible for complying with the standards in the regions in which we operate. NERC will have the ability to assess financial penalties for noncompliance, which could be material.

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, natural gas, and fuels. Changes in energy supply and demand may impact the price of these energy commodities in both the spot market and the forward market, which may affect our results in any given period. Typically, demand for electricity and its price are higher in the summer and the winter, when weather is more extreme. 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, thus we are not typically exposed to the effects of extreme weather in all parts of our business at once.

BGE

Weather affects the demand for electricity and gas for our regulated businesses. Very hot summers and very cold winters increase demand. Mild weather reduces demand. Weather affects residential sales more than commercial and industrial sales, which are mostly affected by business needs for electricity and gas. The Maryland PSC has approved revenue decoupling mechanisms which allow BGE to record monthly adjustments to the majority of our regulated electric and gas business distribution revenues to eliminate the effect of abnormal weather and usage patterns. We discuss this further in the Regulation—Maryland PSC—Revenue Decoupling, Regulated Electric Business—Revenue Decoupling and Regulated Gas Business—Revenue Decoupling sections.

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:

    seasonal, daily, and hourly changes in demand,
    number of market participants,
    extreme peak demands,
    available supply resources,
    transportation and transmission availability and reliability within and between regions,
    location of our generating facilities relative to the location of our load-serving obligations,
    implementation of new market rules governing operations of regional power pools,
    procedures used to maintain the integrity of the physical electricity system during extreme conditions,
    changes in the nature and extent of federal and state regulations, and
    international supply and demand.

        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:

    weather conditions,
    market liquidity,
    capability and reliability of the physical electricity and gas systems,
    local transportation systems, and
    the nature and extent of electricity deregulation.

        Other factors 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

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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 downturn, our customers tend to consume less electricity and gas.

Environmental Matters and Legal Proceedings

We discuss details of our environmental matters in Note 12 to Consolidated Financial Statements and Item 1. Business—Environmental Matters section. We discuss details of our legal proceedings in Note 12 to Consolidated Financial Statements. Some of this information is about costs that may be material to our financial results.

Accounting Standards Adopted and Issued

We discuss recently adopted and issued accounting standards in Note 1 to Consolidated Financial Statements.

Critical Accounting Policies

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

    our reported amounts of revenues and expenses in our Consolidated Statements of Income (Loss),
    our reported amounts of assets and liabilities in our Consolidated Balance Sheets, and
    our disclosure of contingent assets and liabilities.

        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 Securities and Exchange Commission (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 of operations 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, in Note 1 to Consolidated Financial Statements.

Accounting for Derivatives and Hedging Activities

We utilize a variety of derivative instruments in order to manage commodity price risk, interest rate risk, and foreign currency risk. The accounting requirements for derivatives are governed by Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. Because of the extensive nature of its requirements that govern both accounting treatment and documentation, as well as the complexity of the transactions within its scope, applying SFAS No. 133 requires management to exercise judgment in several areas, including the following:

    identification of derivatives,
    selection of accounting treatment for derivatives,
    valuation of derivatives, and
    impact of uncertainty.

        As discussed in more detail below, the exercise of management's judgment in these areas materially impacts our financial statements. While we believe we have appropriate controls in place to apply SFAS No. 133, failure to meet its requirements, even inadvertently, could require the use of a different accounting treatment for the affected transactions. In addition, interpretations of SFAS No. 133 continue to evolve, and a future change in accounting requirements also could affect our financial statements materially. We discuss derivatives and hedging activities in more detail in Note 1 and Note 13 to Consolidated Financial Statements.

Identification of Derivatives

We must evaluate new and existing transactions and agreements to determine whether they are derivatives. Identifying derivatives requires us to exercise judgment in interpreting the definition of a derivative in SFAS No. 133 and applying that definition to each individual contract. If a contract is not a derivative, we cannot apply SFAS No. 133, and we generally must record the effects of the contract in our financial statements upon delivery or settlement under the accrual method of accounting. In contrast, if a contract is a derivative, we must apply SFAS No. 133, which provides for several possible accounting treatments as discussed more fully under Accounting Treatment below. As a result, the required accounting treatment and its impact on our financial statements can vary substantially depending upon whether a contract is a derivative or a non-derivative.

Accounting Treatment

SFAS No. 133 permits several possible accounting treatments for derivatives that meet all of the applicable requirements of that standard. SFAS No. 133 requires mark-to-market as the default accounting treatment for all derivatives unless they qualify, and we affirmatively designate them, for one of the other accounting treatments. Derivatives designated for any of the other elective accounting treatments must meet specific, restrictive criteria prescribed by SFAS No. 133, both at the time of designation and on an ongoing basis.

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        The permissible accounting treatments for derivatives are:

    mark-to-market,
    cash flow hedge,
    fair value hedge, and
    accrual accounting under Normal Purchase/Normal Sale (NPNS).

        Each of the accounting treatments that we use for derivatives affects our financial statements in substantially different ways as summarized below:

 
  Recognition and Measurement
Accounting Treatment
  Balance Sheet
  Income Statement
 
Mark-to-market   •  Recorded at fair value   •  Changes in fair value recognized in earnings
 
Cash flow hedge   •  Recorded at fair value

•  Effective changes in fair value recognized in accumulated other comprehensive income
  •  Ineffective changes in fair value recognized in earnings

•  Amounts in accumulated other comprehensive income reclassified to earnings when the hedged forecasted transaction affects earnings or becomes probable of not occurring
 
Fair value hedge   •  Recorded at fair value

•  Changes in fair value of the hedged asset or liability recorded as adjustment to its book value
  •  Changes in fair value recognized in earnings

•  Changes in fair value of hedged asset or liability recognized in earnings
 
NPNS (accrual)   •  Fair value not recorded

•  Accounts receivable or accounts payable recorded when derivative settles
  •  Changes in fair value not recognized in earnings

•  Revenue or expense recognized in earnings when underlying physical commodity is sold or consumed
 

        We exercise judgment in determining which derivatives qualify for a particular accounting treatment under the provisions of SFAS No. 133 and its interpretations, including:

    Cash flow and fair value hedges—determination that all hedge accounting requirements are satisfied, including the expectation that the derivative will be highly effective in offsetting changes in cash flows or fair value from the risk being hedged and, for cash flow hedges, the probability that the hedged forecasted transaction will occur.
    Accrual accounting under NPNS—determination that the derivative will result in gross physical delivery of the underlying commodity and will not settle net.

        We also exercise judgment in selecting the accounting treatment that we believe provides the most transparent presentation of the economics of the underlying transactions. Although contracts may be eligible for hedge accounting or NPNS designation, SFAS No. 133 does not require all such contracts to be designated and accounted for identically. We generally elect accrual or hedge accounting for our physical energy delivery activities (generation and customer supply) because accrual accounting more closely aligns the timing of earnings recognition, cash flows, and the underlying business activities. By contrast, we generally apply mark-to-market accounting for risk management and trading activities because changes in fair value more closely reflect the economic performance of the activity. However, we also use mark-to-market accounting for the following physical energy delivery activities:

    our nonregulated retail gas customer supply activities, which are managed using economic hedges that we have not designated as cash-flow hedges so as to match the timing of recognition of the earnings impacts of those activities to the greatest extent permissible, and
    economic hedges of activities that require accrual accounting for which the related hedge requires mark-to-market accounting.

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        As a result of making these judgments, the selection of accounting treatments has a material impact on our financial position and results of operations. These impacts affect several components of our financial statements, including assets, liabilities, and accumulated other comprehensive income. Additionally, the selection of accounting treatment also affects the amount and timing of the recognition of earnings. The following table summarizes these impacts:

 
  Accounting Treatment
Effect of Changes
in Fair Value on:

  Mark-to-market
  Cash Flow Hedge
  Fair Value Hedge
  NPNS
 
Assets and liabilities   •  Increase or decrease in derivatives   •  Increase or decrease in derivatives   •  Increase or decrease in derivatives

•  Decrease or increase in hedged asset or liability
  •  No impact
 
Accumulated other comprehensive income (AOCI)   •  No impact   •  Increase or decrease for effective portion of hedge   •  No impact   •  No impact
 
Earnings prior to settlement   •  Increase or decrease   •  Increase or decrease for ineffective portion of hedge   •  Increase or decrease for change in derivatives

•  Decrease or increase for change in hedged asset or liability

•  Increase or decrease for ineffective portion
  •  No impact
 
Earnings at settlement   •  No impact   •  Amounts in AOCI reclassified to earnings when hedged forecasted transaction affects earnings   •  Hedged margin recognized in earnings   •  Revenue or expense recognized in earnings when underlying physical commodity is sold or consumed
 

Valuation

SFAS No. 133 requires us to record mark-to-market and hedge derivatives at fair value, which represents an exit price for the asset or liability from the perspective of a market participant. An exit price is the price at which a market participant could sell an asset or transfer a liability to an unrelated party. While some of our derivatives relate to commodities or instruments for which quoted market prices are available from external sources, many other commodities and related contracts are not actively traded. Additionally, some contracts include quantities and other factors that vary over time. In these cases, we must use modeling techniques to estimate expected future market prices, contract quantities, or both in order to determine fair value.

        The prices, quantities, and other factors we use to determine fair value reflect management's best estimates of inputs a market participant would consider. We record valuation adjustments to reflect uncertainties associated with estimates inherent in the determination of fair value that are not incorporated in market price information or other market-based estimates we use to determine fair value. To the extent possible, we utilize market-based data together with quantitative methods for both measuring the uncertainties for which we record valuation adjustments and determining the level of such adjustments and changes in those levels. We discuss fair value measurements in more detail in Note 13 to Consolidated Financial Statements.

        The judgments we are required to make in order to estimate fair value have a material impact on our financial statements. These judgments affect the selection, appropriateness, and application of modeling techniques, the methods used to identify or estimate inputs to the modeling techniques, and the consistency in applying these techniques over time and across types of derivative instruments. Changes in one or more of these judgments could have a material impact on the valuation of derivatives and, as a result, could also have a material impact on our financial position or results of operations.

Impacts of Uncertainty

The accounting for derivatives and hedging activities involves significant judgment and requires the use of estimates that are inherently uncertain and may change in subsequent periods. The effect of changes in assumptions and estimates could materially impact our reported amounts of revenues and costs and could be affected by many factors including, but not limited to, the following:

    uncertainty surrounding inputs to the estimates of fair value required by SFAS No. 133 due to factors such as illiquid markets or the absence of observable market price information,
    our ability to continue to designate and qualify derivative contracts for NPNS accounting or hedge accounting under the requirements of SFAS No. 133,

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    potential volatility in earnings from ineffectiveness on derivatives for which we have elected hedge accounting, and
    our ability to enter into new mark-to-market derivative origination transactions.

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

Long-Lived Assets

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

    a significant decrease in the market price of a long-lived asset,
    a significant adverse change in the manner an asset is being used or its physical condition,
    an adverse action by a regulator or legislature or an adverse change in the business climate,
    an accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset,
    a current-period loss combined with a history of losses or the projection of future losses, or
    a change in our intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life.

        For long-lived assets that can be classified as held for sale, we recognize an impairment loss to the extent their carrying amount exceeds their fair value less costs to sell. For long-lived assets that we expect to hold and use, we recognize an impairment loss only if the carrying amount of an asset is not recoverable and exceeds its fair value. The carrying amount of an asset is not recoverable if it exceeds the total 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 estimate the undiscounted future cash flows associated with the asset at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. This necessarily requires us to estimate uncertain future cash flows.

        In order to estimate future cash flows, we consider historical cash flows and changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). If we are considering alternative courses of action to recover the carrying amount of a long-lived asset (such as the potential sale of an asset), we probability-weight the alternative courses of action to estimate the cash flows.

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

        If we determine that the undiscounted cash flows from an asset to be held and used are less than the carrying amount of the asset, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. The estimation of fair value also involves judgment. We consider quoted market prices in active markets to the extent they are available. In the absence of such information, we may consider prices of similar assets, consult with brokers, or employ other valuation techniques. Often, we will discount the estimated future cash flows associated with the asset using a single interest rate that is commensurate with the risk involved with such an investment or employ an expected present value method that probability-weights a range of possible outcomes. The use of these methods involves the same inherent uncertainty of future cash flows as discussed above with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in our estimates, and the impact of such variations could be material.

Gas Properties

We evaluate unproved property at least annually to determine if it is impaired under SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Properties. Impairment for unproved property occurs if there are no firm plans to continue drilling, the lease is near its expiration, or historical experience necessitates a valuation allowance.

Investments

We evaluate our equity-method and cost-method investments (for example, CEP and partnerships that own power projects) to determine whether or not they are impaired. Accounting Principles Board (APB) Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock, provides the accounting requirements 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.

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        We continuously monitor issues that potentially could impact future profitability of our equity-method investments that own geothermal, coal, hydroelectric, fuel processing projects, as well as our equity investments in our joint ventures and CEP, including environmental and legislative initiatives. We discuss certain risks and uncertainties in more detail in our Forward Looking Statements and Item 1A. Risk Factors sections. 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.

        Current California statutes and regulations require load-serving entities to increase their procurement of renewable energy resources and mandate statewide reductions in greenhouse gas emissions. Given the need for electric power and the statutory and regulatory requirements increasing demand for renewable resource technologies, we believe California will continue to foster an environment that supports the use of renewable energy and continues certain subsidies that will make renewable energy projects economical. However, should California legislation and regulatory policies and federal energy policies fail to adequately support 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.

Debt and Equity Securities

Our available for sale investments in debt and equity securities, primarily our nuclear decommissioning trust fund assets, are subject to impairment evaluations under FASB Staff Positions SFAS No. 115-1 and SFAS No. 124-1 (FSP 115-1 and 124-1), The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments. FSP 115-1 and 124-1 require us to determine whether a decline in fair value of an investment below book value is other than temporary. If we determine that the decline in fair value is other than temporary, the cost basis of the investment must be written down to fair value as a new cost basis. For securities held in our nuclear decommissioning trust fund for which the market value is below book value, the decline in fair value for these securities is considered other than temporary and must be written down to fair value.

Goodwill

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

Asset Retirement Obligations

We incur legal obligations associated with the retirement of certain long-lived assets. SFAS No. 143, Accounting for Asset Retirement Obligations, provides the accounting for legal obligations associated with the retirement of long-lived assets. We incur such legal obligations as a result of environmental and other government regulations, contractual agreements, and other factors. The application of this standard requires significant judgment due to the large number and diverse nature of the assets in our various businesses and the estimation of future cash flows required to measure legal obligations associated with the retirement of specific assets. FASB Interpretation (FIN) 47, Accounting for Conditional Asset Retirement Obligations—an interpretation of FASB Statement No. 143, clarifies that obligations that are conditional upon a future event are subject to the provisions of SFAS No. 143.

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

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

        In view of the significant number of assumptions underlying the decommissioning cost estimate, our estimate of the future cost of decommissioning is likely to continue to change over time. For perspective, a 10% increase or decrease in our estimate of the future cost of decommissioning our nuclear plants would produce an approximately $96 million change to our asset retirement obligation and an approximately $11 million change in our total annual amortization and accretion expenses.

Significant Events

Execution and Subsequent Termination of Merger Agreement with MidAmerican

On December 17, 2008, Constellation Energy and MidAmerican agreed to terminate the Agreement and Plan of Merger the parties had entered into on September 19, 2008. As a result, we paid MidAmerican:

    $175 million to terminate the merger, and
    $418 million in lieu of the number of shares of our common stock that were due to MidAmerican on conversion of the Series A Preferred Stock but that could not be issued due to regulatory limitations.

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        Additionally, we issued 19.9 million common shares and $1 billion of 14% Senior Notes to MidAmerican in connection with the conversion of the Series A Preferred Stock.

        We discuss the termination of the merger in more detail in Note 15 to Consolidated Financial Statements.

Investment Agreement with EDF

On December 17, 2008, Constellation Energy and EDF and related entities entered into a series of transactions under which:

    EDF will purchase from Constellation Energy a 49.99% membership interest in our nuclear generation and operation business for $4.5 billion (subject to certain adjustments) at closing, and $150 million of cash received in 2008 in addition to this purchase price.
    EDF is providing Constellation Energy with up to $2 billion of additional liquidity pursuant to a put arrangement that will allow us to require EDF to purchase certain non-nuclear generation assets.
    EDF invested $1 billion in Constellation Energy by purchasing 10,000 shares of our 8% Series B Preferred Stock. These shares will be surrendered to us when EDF purchases its membership interest in our nuclear generation and operation business, and the $1 billion will be credited against the $4.5 billion purchase price.
    EDF provided us with a $600 million interim backstop liquidity facility.
    Prior to closing, we will transfer to our nuclear generation and operation business transactions with a negative mark-to-market value not to exceed $700 million in the aggregate using a 10% discount rate. This transfer will occur in a manner that is to be determined and to be mutually acceptable to Constellation Energy and EDF.

        We discuss these transactions in more detail in Note 15 to Consolidated Financial Statements and the Series B Preferred Stock in Note 9 to Consolidated Financial Statements.

Divestitures

In 2009, we made progress on many of the strategic initiatives we identified in 2008 to improve liquidity and reduce our business risk.

        In January 2009, we entered into a definitive agreement to sell a majority of our international commodities operation.

        In February 2009, we entered into a definitive agreement to sell our Houston-based gas trading operation. Simultaneously, we signed a letter of intent to enter into a related transaction with an affiliate of the buyer under which that company would provide us with the gas supply needed to support our retail gas customer supply business, while reducing our credit requirements. We expect that both of these sales will close by the end of the second quarter of 2009, subject to certain regulatory approvals and other standard closing conditions.

        Collectively, we expect both divestitures to return approximately $1 billion of currently posted collateral. In addition, we expect these divestitures to further reduce our downgrade collateral requirements by approximately $400 million. These reductions are based on current commodity prices, the final terms of the transactions, and the timing of collateral to be returned up to the close of the transactions, and, as a result, are subject to change.

        We discuss these divestitures in more detail in Note 3 to Consolidated Financial Statements.

Current Market Developments

As previously discussed in the Business Environment section, during 2008 the financial markets experienced extreme volatility, and this volatility greatly reduced liquidity in the global credit markets. The following highlights the impacts of these developments on us:

    Several of our debt securities were downgraded by the major credit rating agencies, and we remain under review for possible downgrade by Standard & Poors Rating Group and Moody's Investors Service. We discuss our security ratings and downgrade collateral in more detail in the Security Ratings and Collateral sections.
    We were required to post additional collateral with counterparties. We discuss our collateral requirements in more detail in the Cash Flows and Collateral sections.
    We initiated strategic alternatives for our upstream gas properties, our international commodities operation, and our gas trading operation as well as other strategies to improve liquidity and reduce invested capital. We discuss our strategy in more detail in the Strategy section.
    We took various other steps to reduce our exposure to the credit risk of other parties and to improve our own liquidity. We discuss our exposure to credit risk in the Risk Management section and we discuss our liquidity in the Available Sources of Funding section.
    In connection with the proposed merger with MidAmerican, we received $1 billion for preferred stock issued to MidAmerican on September 22, 2008. We subsequently terminated the merger in December 2008, and we repaid the $1 billion (which had converted into 14% Senior Notes at the time of the termination of the merger) plus interest to MidAmerican in January 2009. Simultaneous with the termination of the MidAmerican merger agreement, EDF purchased $1 billion of preferred stock as part of a series of transactions contemplated by the Investment Agreement and other related agreements. We discuss the termination of the merger agreement with MidAmerican, the conversion of MidAmerican's Series A Preferred Stock as well as our transactions with EDF in Note 15 to Consolidated Financial Statements.
    We recorded significant impairment charges in the third and fourth quarters of 2008. We discuss these impairment charges in more detail in Note 2 to Consolidated Financial Statements.
    We incurred losses on our pension plan and nuclear decommissioning trust fund assets. We discuss our pension plan assets in more detail in the Consolidated Nonoperating Income and Expenses section and our nuclear decommissioning trust assets in Item 1.

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Commodity Prices

During 2008, the energy markets were affected by large fluctuations in commodity prices as indicated in the following table summarizing changes in spot prices during 2008:

Increases (decreases) from December 31, 2007
  Six months ended
June 30, 2008

  Nine months ended
September 30, 2008

  Year ended
December 31, 2008

 
   

Power

    33 %   (8 )%   (30 )%

Natural gas

    44 %   (5 )%   (30 )%

Coal

    153 %   58 %   (1 )%

Crude oil

    55 %   1 %   (40 )%

        During the third and fourth quarters of 2008, prices for most commodities, including energy commodities, fell sharply after peaking early in July. The commodity price environment contributed to the following impacts on our results:

    As a result of volatile commodity prices, we experienced significant mark-to-market gains during the six months ended June 30, 2008 and significant mark-to-market losses during the six months ended December 31, 2008. We discuss our mark-to-market results in the Mark-to-Market section.
    Our total derivative assets increased $526.0 million and total derivative liabilities increased $103.6 million since December 31, 2007. We discuss our derivative assets and liabilities in more detail in the Derivative Assets and Liabilities section.
    During 2008, we had significant fluctuations in collateral. We discuss our collateral requirements in more detail in the Cash Flows and Collateral sections.
    We experienced an increase in our exposure to lower credit quality wholesale counterparties during the first half of 2008 and a decrease in our exposure to lower credit quality wholesale counterparties during the latter half of 2008 primarily due to the volatility of coal prices. We discuss our wholesale credit risk exposure in more detail in the Wholesale Credit Risk section.
    One of our domestic coal suppliers was unable to meet production targets and filed for bankruptcy. As a result, in the quarter ended March 31, 2008, we incurred a credit loss related to this supplier. We discuss the impact of this event on our results in more detail in the Global Commodities section.
    We experienced an increase in our allowance for uncollectible accounts receivable. We discuss our allowance for uncollectible accounts receivable in more detail in the Allowance for Uncollectible Accounts Receivable section.
    We executed several contract settlements and amended certain other contracts, primarily in the quarter ended March 31, 2008, to reduce our exposure to supplier nonperformance risk and/or credit risk. We discuss these transactions in more detail in the Global Commodities section.

Workforce Reduction Costs

During the third quarter of 2008, our merchant energy business approved a restructuring of its Customer Supply operations and recognized a $2.5 million pre-tax charge.

        During the fourth quarter of 2008, we approved a broader restructuring of our operations and recognized a $19.7 million pre-tax charge.

        We discuss our workforce reduction costs in more detail in Note 2 to Consolidated Financial Statements.

Emission Allowances

During the second and third quarters of 2008, as a result of a July 11, 2008 decision by the United States Court of Appeals for the D. C. Circuit that vacated the Clean Air Interstate Rule (CAIR) and the subsequent decline in market price for our emission allowance inventory, we recorded a write-down of our emissions inventory and recognized partially offsetting gains on certain forward sales contracts. In December 2008, CAIR was reinstated and the market prices for our emission allowance inventory increased. We reversed a portion of the previous write-downs of this inventory to reflect the subsequent increase in market prices. We discuss this net charge in Note 2 to Consolidated Financial Statements.

Acquisitions

Hillabee Energy Center

On February 14, 2008, we acquired a partially completed gas-fired power generating facility in Alabama. We discuss this acquisition in more detail in Note 15 to Consolidated Financial Statements.

West Valley Power Plant

On June 1, 2008, we acquired a gas-fired peaking plant in Utah. We discuss this acquisition in more detail in Note 15 to Consolidated Financial Statements.

Nufcor International Limited

On June 26, 2008, we acquired a uranium marketing services company in the United Kingdom. We discuss this acquisition in more detail in Note 15 to Consolidated Financial Statements.

Asset Sales

Working Interests in Gas Producing Property

In 2008, we sold the following:

    a portion of our working interests in proved and unproved gas properties in Arkansas,
    our working interest in oil and natural gas producing properties to Constellation Energy Partners LLC (CEP), a related party, and
    our working interests in proved natural gas reserves in Wyoming, and our equity investment in certain entities that own interests in proved natural gas reserves and unproved properties in Texas and Montana.

        We discuss these asset sales in more detail in Note 2 to Consolidated Financial Statements.

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Dry Bulk Vessel

On July 10, 2008, a shipping joint venture in which our merchant energy business owns a 50% ownership interest sold one of six dry bulk vessels it owns for a gain to us of approximately $29 million. We discuss this sale in more detail in Note 2 to Consolidated Financial Statements.

Financing Activities

In June 2008, we issued the following:

    $250.0 million of Zero Coupon Senior Notes due June 2023, and
    $450.0 million of 8.625% Series A Junior Subordinated Debentures due June 2063.

        Also, in June 2008, BGE issued $400.0 million of 6.125% Notes due July 1, 2013.

        In connection with the merger agreement with MidAmerican, we issued 10,000 shares of 8% Series A Convertible Preferred Stock to MidAmerican. Upon termination of the merger agreement in December 2008, this Preferred Stock converted into $1 billion of 14% Senior Notes of Constellation Energy due December 31, 2009, 19.9 million common shares (9.9% of our outstanding shares), and $418 million in cash.

        In connection with the Investment Agreement with EDF, Constellation Energy issued shares of mandatorily redeemable 8% Series B Preferred Stock for $1 billion, which shares will be surrendered to us when EDF purchases its interest in our nuclear generation and operation business (and will be credited against the $4.5 billion purchase price, or, if the transaction does not close, will be redeemed at the later of the termination date or December 31, 2009 for $1 billion of 10% Senior Notes due June 30, 2010). The $1 billion proceeds from this issuance is restricted for the payment of our 14% Senior Notes held by MidAmerican. In January 2009, we repaid the 14% Senior Notes using these proceeds.

        We discuss our financing activities in more detail in Note 9 to Consolidated Financial Statements.

        As part of the Investment Agreement with EDF, EDF agreed to a put arrangement under which Constellation Energy could, at its option, sell to EDF certain non-nuclear generation assets having an aggregate value of up to $2 billion. We discuss the Investment Agreement in more detail in Note 15 to Consolidated Financial Statements.

        In addition, EDF has also agreed to provide us with a $600 million interim backstop liquidity facility. We discuss this facility in more detail in Note 8 to Consolidated Financial Statements.

Maryland Settlement Agreement

In March 2008, Constellation Energy, BGE, and a Constellation Energy affiliate entered into a settlement agreement with the State of Maryland, the Maryland PSC, and certain State of Maryland officials to resolve pending litigation and to settle other prior legal, regulatory, and legislative issues. We discuss this settlement in more detail in Note 2 to Consolidated Financial Statements.

Results of Operations

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

        As discussed in Part I. Item 1 Business—Overview section and in the Strategy and Significant Events sections, Constellation Energy's 2008 operating results were materially impacted by a number of significant events, transactions, and resulting changes in the our strategic direction. The impact of these items has affected the comparability of our 2008 results to prior periods and will alter Constellation Energy's operating results in the future. In this section, we highlight the 2008 impact of these items.

Overview

Results

 
  2008
  2007
  2006
 
   
 
  (In millions, after-tax)
 

Merchant energy

  $ (1,357.4 ) $ 679.2   $ 580.1  

Regulated electric

    1.1     97.9     120.2  

Regulated gas

    37.2     28.8     37.0  

Other nonregulated

    4.7     16.5     11.3  
   

(Loss) Income from continuing operations and before cumulative effects of changes in accounting principles

    (1,314.4 )   822.4     748.6  
 

(Loss) income from discontinued operations

        (0.9 )   187.8  
   

Net (Loss) Income

  $ (1,314.4 ) $ 821.5   $ 936.4  
   

Other Items Included in Operations (after-tax)

                   
 

Impairments and other costs

  $ (468.4 ) $ (12.2 ) $  
 

Merger termination and strategic alternatives costs:

                   
   

Merger termination costs

    (1,134.4 )       (5.7 )
   

Strategic alternatives costs

    (70.0 )        
 

Maryland settlement credit

    (126.5 )        
 

Effective tax rate impact of Maryland settlement agreement

    16.0          
 

Impairment of nuclear decommissioning trust assets

    (82.0 )        
 

Emission allowance write down, net

    (28.7 )        
 

Non-qualifying hedges

    (70.1 )   2.0     39.2  
 

Gain on sale of gas-fired plants

            47.1  
 

Workforce reduction costs

    (13.4 )   (1.4 )   (17.0 )
   

Total Other Items

  $ (1,977.5 ) $ (11.6 ) $ 63.6  
   

Change from prior year

  $ (1,965.9 ) $ (75.2 )      
         

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2008

Our total net loss for 2008 exceeded net income for 2007 by $2,135.9 million, or $11.84 per share, mostly because of the following:

 
  2008 vs. 2007
 
   
(in millions, after-tax)

 

Generation gross margin

  $ 137  

Customer Supply gross margin

    (79 )

Global Commodities gross margin

    (97 )

Sale of upstream gas assets

    16  

2007 sale of CEP LLC equity

    (39 )

Hedge ineffectiveness

    (26 )

Credit loss—coal supplier bankruptcy

    (33 )

Merchant operating expenses excluding bad debt expense, primarily labor and benefit costs

    57  

Merchant bad debt expense

    (19 )

Merchant interest expense

    (63 )

Synthetic fuel facilities

    (9 )

Other nonregulated businesses

    (12 )

Total change in Other Items included in operations per Overview—Results table

    (1,966 )

Interest and investment income

    (35 )

All other changes

    32  
   

Total Change

  $ (2,136 )
   

2007

Our total net income for 2007 decreased $114.9 million, or $0.66 per share, compared to 2006 mostly because of the following:

 
  2007 vs. 2006
 
   
(in millions, after-tax)

 

Generation gross margin

  $ 98  

Customer supply and global commodities earnings, primarily higher gross margin, partially offset by higher operating expenses

    23  

Absence of 2006 gain on sale—High Desert

    (189 )

Gain on sales of CEP equity

    21  

Synthetic fuel facilities

    (34 )

Regulated operations, primarily impact of Senate Bill 1 and higher operations and maintenance expenses

    (31 )

Total change in Other Items included in operations per Overview—Results table

    (75 )

Interest and investment income

    70  

All other changes

    2  
   

Total Change

  $ (115 )
   

Merchant Energy Business

Background

Our merchant energy business is a competitive provider of energy solutions for various customers. We discuss the impact of deregulation on our merchant energy business in Item 1. Business—Competition section.

        Our merchant energy business focuses on delivery of physical, customer-oriented products to producers and consumers, manages the risk and optimizes the value of our owned generation assets and customer supply activities, and uses our portfolio management and trading capabilities both to manage risk and to deploy risk capital.

        We are continuing to assess the ongoing capital requirements of the merchant energy business, including evaluating the proper size of our Customer Supply and Global Commodities operations, and we are pursuing various strategic initiatives for our Global Commodities operation. As previously discussed, we have made substantial changes in our strategy. We discuss our strategy in more detail in the Strategy section.

        While we have entered into definitive agreements in 2009 for the sale of a majority of our international commodities operation and our gas trading operation, the execution of our strategy in the future will be affected by continued instability in financial, credit, and commodities markets. Execution of our goals could have a substantial effect on the nature and mix of our business activities. In particular, upon closing the transactions contemplated by our Investment Agreement with EDF, we expect that our subsidiary that owns our nuclear generation assets will be deconsolidated. In turn, this could affect our financial position, results of operations, and cash flows in material amounts, and these amounts could vary substantially from historical results. We discuss our asset and operation divestitures in more detail in Note 3 to Consolidated Financial Statements.

        We record merchant energy revenues and expenses in our financial results in different periods depending upon which portion of our business they affect and based on the associated accounting policies. We discuss our revenue recognition policies in the Critical Accounting Policies section and in Note 1 to Consolidated Financial Statements.

        Our Global Commodities operation actively transacts in energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions. As part of these activities, we trade energy and energy-related commodities and deploy risk capital in the management of our portfolio in order to earn additional returns. We manage these activities through daily value at risk and stop loss limits and liquidity guidelines, and they can have a material impact on our financial results. We discuss the impact of our trading activities and value at risk in more detail in the Mark-to-Market and Risk Management sections.

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Results

 
  2008
  2007
  2006
 
   
 
  (In millions)
 

Revenues

  $ 16,772.8   $ 18,744.5   $ 17,166.2  

Fuel and purchased energy expenses

    (13,791.4 )   (15,501.8 )   (14,256.3 )

Operating expenses

    (1,729.7 )   (1,791.8 )   (1,549.4 )

Impairment losses and other costs

    (741.8 )   (20.2 )    

Workforce reduction costs

    (15.4 )   (2.3 )   (28.2 )

Merger termination and strategic alternatives costs

    (1,204.4 )       (13.1 )

Depreciation, depletion, and amortization

    (287.1 )   (269.9 )   (258.7 )

Accretion of asset retirement obligations

    (68.4 )   (68.3 )   (67.6 )

Taxes other than income taxes

    (124.3 )   (110.2 )   (120.0 )

Gains on sales of upstream gas assets

    25.5          

Gain on sale of gas-fired plants

            73.8  
   

(Loss) Income from Operations

  $ (1,164.2 ) $ 980.0   $ 946.7  
   

(Loss) Income from continuing operations and before cumulative effects of changes in accounting principles (after-tax)

  $ (1,357.4 ) $ 679.2   $ 580.1  
 

(Loss) Income from discontinued operations (after-tax)

        (0.9 )   186.9  
   

Net (Loss) Income

  $ (1,357.4 ) $ 678.3   $ 767.0  
   

Other Items Included in Operations (after-tax)

                   
 

Impairments and other costs

  $ (468.4 ) $ (12.2 ) $  
 

Merger termination and strategic alternatives costs

    (1,204.4 )       (4.3 )
 

Impairment of nuclear decommissioning trust assets

    (82.0 )        
 

Emission allowance write-down, net

    (28.7 )        
 

Gain on sale of gas-fired plants

            47.1  
 

Non-qualifying hedges

    (70.1 )   2.0     39.2  
 

Workforce reduction costs

    (9.3 )   (1.4 )   (17.0 )
   

Total Other Items

  $ (1,862.9 ) $ (11.6 ) $ 65.0  
   

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

Revenues and Fuel and Purchased Energy Expenses

Our merchant energy business manages the revenues we realize from the sale of energy and energy-related products to our customers and our costs of procuring fuel and energy. The difference between revenues and fuel and purchased energy expenses, including all direct expenses, represents the gross margin of our merchant energy business, and this measure is a useful tool for assessing 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 gross margin between periods. In managing our portfolio, we may terminate, restructure, or acquire contracts. Such transactions are within the normal course of managing our portfolio and may materially impact the timing of our recognition of revenues, fuel and purchased energy expenses, and cash flows.

        In the third quarter of 2007, we changed the management of the wholesale procurement function for retail gas activities from our Customer Supply operation to our Global Commodities operation. In connection with this change, we began to prospectively account for the underlying retail gas contracts as derivative contracts subject to mark-to-market accounting, under which changes in fair value are recorded in revenues as they occur. This activity was previously accounted for on a gross basis and recorded in accrual revenues and fuel and purchased energy expenses. The change to market-to-market accounting for this activity reduced both our accrual revenues and fuel and purchased energy expenses in 2008 and 2007. However, the change had a minimal impact on gross margin.

        We discuss our merchant energy revenues, fuel and purchased energy expenses, and gross margin below.

Revenues

Our merchant energy revenues decreased $1,971.7 million in 2008 compared to 2007 and increased $1,578.3 million in 2007 compared to 2006 primarily due to the following:

 
  2008
vs. 2007

  2007
vs. 2006

 
   
 
  (In millions)
 

Change in Global Commodities mark-to-market revenues due to (unfavorable) favorable changes in power and gas prices

  $ (403 ) $ 71  

Change in contract prices and volume of business primarily related to our coal and international freight operation

    (281 )   716  

Realization of higher contract prices on wholesale and retail load at our Global Commodities and Customer Supply operations

    658     1,152  

All other (substantially all due to change in gas procurement activities)

    (1,946 )   (361 )
   

Total (decrease) increase in merchant revenues

  $ (1,972 ) $ 1,578  
   

Fuel and Purchased Energy Expenses

Our merchant energy fuel and purchased energy expenses decreased $1,710.4 million in 2008 compared to 2007 and increased $1,245.5 million in 2007 compared to 2006 primarily due to the following:

 
  2008
vs. 2007

  2007
vs. 2006

 
   
 
  (In millions)
 

Change in Global Commodities mark-to-market expenses related to international coal purchase contracts

  $ (106 ) $ 18  

Change in contract prices and volume of business primarily related to our coal and freight operation

    (238 )   733  

Realization of higher contract prices on wholesale and retail purchases at our Global Commodities and Customer Supply operations

    710     813  

(Decrease) increase in synfuels expenses due to expiration of tax credits in 2007

    (141 )   36  

All other (substantially all due to change in gas procurement activities)

    (1,935 )   (354 )
   

Total decrease in merchant energy revenues

  $ (1,710 ) $ 1,246  
   

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Gross Margin

We analyze our merchant energy gross margin in the following categories.

    Generation—our operation that owns, operates, and maintains fossil, nuclear, and renewable generating facilities and holds interests in qualifying facilities, and power projects in the United States and Canada. We present the gross margin results of this operation based on a 100% hedged assumption for the portfolio, related to both output from the facilities and the fuel used to generate electricity. The assumption is based on executing hedges at current market prices with the Global Commodities operation at the end of each prior fiscal year in order to ensure that the Generation operation is fully hedged. Therefore, all commodity price risk is managed by and presented in the results of our Global Commodities operation as discussed below. Changes in gross margin of our Generation operation during the period are due to changes in the level of output from the generating assets, and changes in gross margin between years are a result of changes in prices and expected output.
    Customer Supply—our load-serving operation that provides energy products and services to wholesale and retail electric and natural gas customers, including distribution utilities, cooperatives, aggregators, and commercial, industrial and governmental customers. We present the gross margin results of this operation based on the gross margin value of new customer supply arrangements at the time of execution assuming an estimated level of customer usage and the impact of any changes in the underlying usage of the customers based on actual energy deliveries. Changes in estimated customer usage result from attrition (customers changing suppliers) or variable load risk (changes in actual usage when compared to expected usage). All commodity price risk is presented in and managed by our Global Commodities operation.
    Global Commodities—our marketing, risk management, and trading operation that manages contractually owned physical assets, including generation facilities, natural gas properties, international coal sourcing and freight assets, provides risk management services, uranium marketing services, and trades energy and energy-related commodities. This operation provides the wholesale risk management function for our Generation and Customer Supply operations, as well as our structured products and energy investments portfolios, and includes our merchant energy business' actual hedged positions with third parties. Therefore, changes in gross margin for this operation result mostly from changes in commodity prices and positions across the various commodities and regions in which we transact.

        We provide a summary of our gross margin for these three components of our merchant energy business as follows:

 
  2008
  2007
  2006
 
   
 
  (Dollar amounts in millions)
 
 
   
  % of
Total
   
  % of
Total
   
  % of
Total
 

Gross margin:

                                     
 

Generation

  $ 1,956     66 % $ 1,700     53 % $ 1,490     51 %
 

Customer Supply

    765     25     889     27     764     26  
 

Global Commodities

    260     9     654     20     656     23  
   

Total

  $ 2,981     100 % $ 3,243     100 % $ 2,910     100 %
   

        In December 2006, we completed the sale of these gas-fired plants:

Facility   Capacity
(MW)
  Unit Type   Location

High Desert

    830   Combined Cycle   California

Rio Nogales

    800   Combined Cycle   Texas

Holland

    665   Combined Cycle   Illinois

University Park

    300   Peaking   Illinois

Big Sandy

    300   Peaking   West Virginia

Wolf Hills

    250   Peaking   Virginia

        This sale impacted our results of operation and cash flows for 2006 when compared to 2007. We discuss the sale of these gas-fired generating facilities in Note 2 to Consolidated Financial Statements.

Generation

The $256 million increase in Generation gross margin in 2008 compared to 2007 is primarily due to the following:

    $245 million increase from higher energy prices for the output of our generating assets in the PJM and New York regions based on prices established at the end of 2007 (see Global Commodities discussion below for impact of price changes during 2008), and
    $11 million of higher earnings for lower planned and unplanned outages at our nuclear and fossil plants.

        The $210 million increase in generation gross margin in 2007 compared to 2006 is primarily due to approximately $290 million increase from higher energy prices for the output of our generating assets in the PJM and New York regions based on prices established at the end of 2006 (see Global Commodities discussion below for impact of price changes during 2007). This increase was partially offset by lower gross margin due to the absence of approximately $80 million of gross margin associated with the gas plants that were sold in December 2006.

Customer Supply

The $124 million decrease in Customer Supply gross margin in 2008 compared to 2007 is primarily due to the following:

    $112 million of lower gross margin related to unfavorable price movements and lower volumes in our retail power operation,

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    $49 million of lower gross margin related to lower realization of contracts executed in prior periods and lower new business originated and realized during the year at our wholesale power operation, and
    $27 million of lower mark-to-market results in our retail gas operation. We discuss this in more detail in the Mark-to-Market section.

        These decreases were partially offset by approximately $64 million of higher gross margin related to our retail gas operation primarily due to the acquisition of Cornerstone Energy on July 1, 2007.

        The $125 million increase in Customer Supply gross margin in 2007 compared to 2006 is primarily due to approximately $182 million of higher realization of contracts executed in prior periods and new contracts executed, including the portfolio of contracts acquired in the southeast United States, primarily for our wholesale and retail power operations. These increases were partially offset by the following:

    $30 million of lower gross margin related to lower prices, partially offset by higher volumes related to our retail gas operation, and
    $27 million of lower mark-to-market results in our retail gas operation. We discuss this in more detail in the Mark-to-Market section.

Global Commodities

We present Global Commodities results in the following categories:

    Portfolio Management and Trading—our centralized risk management service related to energy price risk associated with our generation fleet, wholesale and retail customer supply business, and our structured products portfolio. It also deploys risk capital in traded energy markets.
    Structured Products—customized risk management products in the power, gas, coal and freight markets (e.g., generation tolls, gas transport and storage, and global coal and freight logistics).
    Energy Investments—investments in energy assets that primarily include natural gas properties and a joint interest in an entity that owns dry bulk cargo vessels.

        As previously discussed in the Significant Events section, the energy markets were affected by substantial volatility in commodity prices during 2008. These market impacts are reflected in the $394 million decrease in gross margin from our Global Commodities operation during 2008 compared to the same period of 2007 primarily due to $698 million of lower gross margin in our portfolio management and trading activities, partially offset by $208 million of higher gross margin in our structured products portfolio and $96 million of higher gross margin in our energy investments portfolio. We discuss these changes below.

        The $698 million of lower gross margin related to our portfolio management and trading operation are due to the following:

    $282 million of lower gross margin related to our portfolio of contracts subject to mark-to-market accounting. We discuss these transactions in more detail in the Mark-to-Market section.
    $206 million of lower gross margin related to portfolio management of positions arising from our Generation, Customer Supply, structured products, and energy investments activities due to the impact of unfavorable changes in prices of power, natural gas, and coal on those positions (see the description of the effects of pricing on Generation and Customer Supply activities,
    $70 million related to write-downs of our emission allowance inventory to reflect current market price decreases. We discuss this in more detail in Note 2 to Consolidated Financial Statements.
    $55 million related to the bankruptcy of one of our domestic coal suppliers. During the first quarter of 2008, as a result of a default by the supplier, we terminated our derivative contracts with the supplier, reclassified the related asset to accounts receivable, and fully reserved the amount.
    $43 million related to losses recognized on hedges due to ineffectiveness and certain cash-flow hedges that no longer qualified for hedge accounting.
    On October 31, 2008, we discontinued the use of hedge accounting for derivative contracts that previously were accounted for as cash-flow hedges within the international commodities operation. From that date, subsequent changes in fair value of those derivative contracts have been recorded in earnings. At December 31, 2008, we concluded that the combination of the decline in value associated with the previously hedged transactions together with the related balances remaining in accumulated other comprehensive income, would lead to the recognition of a net loss in one or more future periods. As such, we recognized a loss of $42 million during the fourth quarter of 2008.

        These decreases in gross margin related to our portfolio management and trading activities are partially offset by higher gross margin of:

    $208 million from gains in our structured products portfolio, consisting of approximately $135 million as a result of the termination and sale of in-the-money energy purchase contracts, coal supply contracts, and freight contracts to eliminate or reduce operation and performance risk with certain counterparties, and approximately $73 million related to higher realization of contracts executed in prior periods, and
    $96 million in our energy investments operation primarily due to approximately $67 million related to higher realization of contracts executed in prior periods and a $29 million gain on sale of a dry bulk vessel in our shipping joint venture. We discuss this sale in more detail in Note 2 to Consolidated Financial Statements.

        The $2 million decrease in gross margin from our Global Commodities operation in 2007 as compared to the same period in 2006 is primarily due to lower gross margin of $43 million in our portfolio management and trading operation and $34 million of lower gross margin in our structured products

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portfolio, partially offset by higher gross margin of $75 million related to our energy investments portfolio. We discuss these changes below.

        The decrease in gross margin of $43 million as a result of portfolio management and trading is primarily related to the following:

    $139 million related to losses recognized on hedges due to ineffectiveness and certain cash-flow hedges that no longer qualified for hedge accounting during the year,
    $72 million of lower gross margin related to portfolio management of positions arising from our Generation, Customer Supply, and structured products activities due to the impact of unfavorable changes in prices of power, natural gas, and coal on those positions (see the description of the effects of pricing on Generation and Customer Supply activities in the preceding sections).

        These decreases were partially offset by $168 million of higher gross margin related to our portfolio of contracts subject to mark-to-market accounting, including higher earnings of $28 million related to increased origination gains primarily associated with nonderivative contracts that were amended to reduce counterparty nonperformance risk, resulting in the contracts becoming derivatives for which mark-to-market accounting is required. We discuss these transactions in more detail in the Mark-to-Market section,

        The decrease in gross margin of $34 million for the structured products portfolio is primarily related to fewer contract terminations and sales during 2007 as compared to 2006.

        These decreases were partially offset by an increase in gross margin of $75 million from the energy investments portfolio, primarily related to the following:

    $44 million of earnings related to our natural gas properties, including the acquisition of working interests in gas producing fields in Oklahoma. We discuss this in more detail in the Note 15 to Consolidated Financial Statements, and
    $31 million due to higher realization from contracts executed in prior periods and higher new business originated and realized during the period.

Mark-to-Market

Mark-to-market results include net gains and losses from origination, trading, and risk management activities for which we use the mark-to-market method of accounting. We discuss these activities and the mark-to-market method of accounting in more detail in the Critical Accounting Policies section and in Note 1 to Consolidated Financial Statements.

        As a result of the nature of our operations and the use of mark-to-market accounting for certain activities, mark-to-market earnings will fluctuate. We cannot predict these fluctuations, but the impact on our earnings could be material. We discuss our market risk in more detail in the Risk Management section. The primary factors that cause fluctuations in our mark-to-market results are:

    changes in the level and volatility of forward commodity prices and interest rates,
    counterparty creditworthiness,
    the number and size of our open derivative positions, and
    the number, size, and profitability of new transactions, including termination or restructuring of existing contracts.

        As discussed earlier, we are currently assessing the ongoing capital requirements of the merchant energy business and are pursuing various alternative strategies. Additionally, we have focused our activities on reducing capital requirements, reducing long-term economic risk, and reducing short-term liquidity requirements. These actions may impact the future results of the merchant energy business, particularly the size of and potential for changes in fair value of activities subject to mark-to-market accounting.

        The primary components of mark-to-market results are origination gains and gains and losses from risk management and trading activities.

        Origination gains arise primarily from contracts that our Global Commodities operation structures to meet the risk management needs of our customers or relate to our trading activities. Transactions that result in origination gains may be unique and provide the potential for individually significant revenues and gains from a single transaction.

        Risk management and trading—mark-to-market represents both realized and unrealized gains and losses from changes in the value of our portfolio, including the effects of changes in valuation adjustments. In addition to our fundamental risk management and trading activities, we also use non-trading derivative contracts subject to mark-to-market accounting to manage our exposure to changes in market prices as a result of our gas transportation and storage activities, while in general the underlying physical transactions related to our gas transportation and storage and freight activities are accounted for on an accrual basis. We use other non-trading derivative transactions subject to mark-to-market accounting to manage our exposure to changes in market prices related to our other activities that are accounted for on an accrual basis.

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

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        Mark-to-market results were as follows:

 
  2008
  2007
  2006
 
   
 
  (In millions)
 

Unrealized mark-to-market results

                   
 

Origination gains

  $ 73.8   $ 41.9   $ 13.5  
 

Risk management and trading—mark-to-market

                   
   

Unrealized changes in fair value

    159.8     500.8     387.4  
   

Changes in valuation techniques

             
   

Reclassification of settled contracts to realized

    48.2     (369.3 )   (372.1 )
   
 

Total risk management and trading—mark-to-market

    208.0     131.5     15.3  
   

Total unrealized mark-to-market*

    281.8     173.4     28.8  

Realized mark-to-market

    (48.2 )   369.3     372.1  
   

Total mark-to-market results

  $ 233.6   $ 542.7   $ 400.9  
   
*
Total unrealized mark-to-market is the sum of origination transactions and total risk management and trading—mark-to-market.

        Total mark-to-market results decreased $309.1 million during the year ended December 31, 2008 compared to the same period of 2007 primarily due to unrealized changes in fair value. The period-to-period variance in unrealized changes in fair value was primarily due to lower gains from unrealized changes in fair value of $341.0 million from risk management and trading, partially offset by an increase in origination gains of $31.9 million. We discuss the increase in origination gains below.

        The net decrease in risk management and trading gains of $341.0 million was primarily due to:

    $619 million of increased losses primarily related to power and transmission trading activities in the northeast, PJM, and ERCOT regions due to unfavorable price movements, execution of transactions to reduce our risk position consistent with changes in our strategy, and execution of those transactions in less liquid market conditions,
    lower gains of $29 million from our emissions trading activities due primarily to unfavorable price movements, and
    $104 million of increased losses related to unfavorable price movements on certain economic hedges of accrual transactions, primarily related to gas transportation and storage and freight activities that do not qualify for or are not designated as cash-flow hedges.

        The risk management and trading results were partially offset by:

    $356 million of gains primarily as a result of favorable price movements relating to economic hedges which substantially increased in value as coal prices decreased in the fourth quarter of 2008. These positions were previously accounted for as cash-flow hedges and were de-designated due to the announced sale of our international commodities operation, and
    $55 million of gains primarily related to our wholesale and retail gas businesses due to favorable price movements on our sales of wholesale and retail natural gas.

        Total mark-to-market results increased $141.8 million during the year ended December 31, 2007 compared to the same period of 2006 primarily due to:

    higher gains from unrealized changes in fair value of $113.4 million, and
    an increase in origination gains of $28.4 million.

        We discuss the increase in origination gains below.

        The $113.4 million in higher gains from unrealized changes in fair value was primarily driven by:

    $73 million of gains related to our emissions trading activities due primarily to favorable price movements,
    $69 million of gains related to our coal and freight portfolio management and trading activities primarily due to favorable price movements, and
    $13 million of gains related to power, transmission, and natural gas in the northeast, PJM, and ERCOT regions due to favorable price movements and increased volume.

        These gains were partially offset by $42 million of losses related to unfavorable price movements on certain economic hedges of accrual transactions that do not qualify for or are not designated as cash-flow hedges, primarily relating to gas transportation and storage and freight activities.

        Origination gains arose primarily from:

    6 transactions in 2008, which are discussed in more detail below, and
    1 transaction in 2007, which is discussed in more detail below.

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

        During 2008, our Global Commodities operation amended certain nonderivative contracts to mitigate counterparty performance risk under the existing contracts. As a result of these amendments, the revised contracts are derivatives subject to mark-to-market accounting under SFAS No. 133. The change in accounting for these contracts from nonderivative to derivative resulted in substantially all of the origination gains for 2008 presented in the table above.

        During 2007, our Global Commodities operation amended certain nonderivative power sales contracts such that the new contracts became derivatives subject to mark-to-market accounting under SFAS No. 133. Simultaneous with the amending of the nonderivative contracts, we executed at current market prices several new offsetting derivative power purchase contracts subject to mark-to-market accounting. The combination of these transactions resulted in substantially all of the origination gains presented for 2007 in the preceding table,

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as well as mitigated our risk exposure under the amended contracts.

        The origination gains in 2007 from these transactions was partially offset by approximately $12 million of losses in our accrual portfolio due to the reclassification of losses related to cash-flow hedges previously established for the amended nonderivative contracts from "Accumulated other comprehensive loss" into earnings. In the absence of these transactions, the economic value represented by the origination gains and the losses associated with cash-flow hedges would have been recognized over the remaining term of the contracts, which extended through the first quarter of 2009.

Derivative Assets and Liabilities

Derivative assets and liabilities consisted of the following:

At December 31,
  2008
  2007
 
   
 
  (In millions)
 

Current assets

  $ 1,465.0   $ 760.6  

Noncurrent assets

    851.8     1,030.2  
   

Total assets

    2,316.8     1,790.8  
   

Current liabilities

    1,241.8     1,134.3  

Noncurrent liabilities

    1,115.0     1,118.9  
   

Total liabilities

    2,356.8     2,253.2  
   

Net derivative position

  $ (40.0 ) $ (462.4 )
   

Composition of net derivative exposure:

             

Hedges

  $ (1,837.6 ) $ (937.6 )

Mark-to-market

    1,485.9     673.0  

Net cash collateral included in derivative balances

    311.7     (197.8 )
   

Net derivative position

  $ (40.0 ) $ (462.4 )
   

        As discussed in our Critical Accounting Policies section, our "Derivative assets and liabilities" include contracts accounted for as hedges and those accounted for on a mark-to-market basis. These amounts are presented in our Consolidated Balance Sheets after the impact of netting, which is discussed in more detail in Note 1 to Consolidated Financial Statements. Due to the impacts of commodity prices, the number of open positions, master netting arrangements, and offsetting risk positions on the presentation of our derivative assets and liabilities in our Consolidated Balance Sheets, we believe an evaluation of the net position is the most relevant measure, and is discussed in more detail below. However, we present our gross derivatives as required by SFAS No. 157, Fair Value Measurements, in Note 13 to Consolidated Financial Statements.

        The increase of $900.0 million in our net derivative liability subject to hedge accounting since December 31, 2007 was due primarily to $1,232 million of unrealized losses associated with existing hedge positions due to unfavorable price changes. These losses were partially offset by $332 million related to the settlement of out-of-the-money cash-flow hedges during 2008. To the extent that these hedges are effective, these unrealized losses will be offset by unrealized gains on the related hedged transactions that will be realized when those transactions affect earnings. We record any hedge ineffectiveness in earnings as it occurs.

        The following are the primary sources of the change in our net derivative asset subject to mark-to-market accounting during 2008 and 2007:

 
  2008
  2007
 
   
 
  (In millions)
 

Fair value beginning of year

        $ 673.0         $ 454.1  

Changes in fair value recorded in earnings

                         
 

Origination gains

  $ 73.8         $ 41.9        
 

Unrealized changes in fair value

    159.8           500.8        
 

Changes in valuation techniques

                     
 

Reclassification of settled contracts to realized

    48.2           (369.3 )      
                       

Total changes in fair value

          281.8           173.4  

Changes in value of exchange-listed futures and options

          571.3           18.6  

Net change in premiums on options

          19.2           (19.0 )

Contracts acquired

                    83.8  

Other changes in fair value

          (59.4 )         (37.9 )
   

Fair value at end of year

        $ 1,485.9         $ 673.0  
   

        Changes in our net derivative asset subject to mark-to-market accounting that affected earnings were as follows:

    Origination gains represent the initial unrealized fair value at the time these contracts are executed to the extent permitted by applicable accounting rules.
    Unrealized changes in fair value represent unrealized changes in commodity prices, the volatility of options on commodities, the time value of options, and other valuation adjustments.
    Changes in valuation techniques represent improvements in estimation techniques, including modeling and other statistical enhancements used to value our portfolio to more accurately reflect the economic value of our contracts.
    Reclassification of settled contracts to realized represents the portion of previously unrealized amounts settled during the period and recorded as realized revenues.

        The net mark-to-market derivative asset also changed due to the following items recorded in accounts other than in our Consolidated Statements of Income (Loss):

    Changes in value of exchange-listed futures and options are adjustments to remove unrealized revenue from exchange-traded contracts that are included in nonregulated revenues. The fair value of these contracts is recorded in "Accounts receivable" rather than "Derivative assets" in our Consolidated Balance Sheets because these amounts are settled through our margin account with a third-party broker.
    Net changes in premiums on options reflects the accounting for premiums on options purchased as an increase in the net derivative asset and premiums on options sold as a decrease in the net derivative asset.

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    Contracts acquired represents the initial fair value of acquired derivative contracts recorded in "Derivative assets and liabilities" in our Consolidated Balance Sheets.
    Other changes in fair value include transfers of derivative assets and liabilities between accounting methods resulting from the designation and de-designation of cash-flow hedges.

        Effective January 1, 2008, we adopted SFAS No. 157 for our financial assets and liabilities, which defines fair value, establishes a framework for measuring fair value, and requires certain disclosures about fair value measurements. Fair value is the price that a market participant would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

        Consistent with the exit price concept, upon adoption we reduced our derivative liabilities to reflect our own credit risk. As a result, during the first quarter of 2008 we recorded a pre-tax reduction in "Accumulated other comprehensive loss" totaling $10 million for the portion related to cash-flow hedges and a pre-tax gain in earnings totaling $3 million for the remainder of our derivative liabilities. All other impacts of adoption were immaterial. We discuss SFAS No. 157 and how we determine fair value in more detail in Note 13 to Consolidated Financial Statements.

        The settlement terms of the portion of our net derivative asset subject to mark-to-market accounting and sources of fair value based on the fair value hierarchy established by SFAS No. 157 are as follows as of December 31, 2008:

 
  Settlement Term    
 
 
  2009
  2010
  2011
  2012
  2013
  2014
  Thereafter
  Fair Value
 
   
 
  (In millions)
 

Level 1

  $ (19.9 ) $   $   $   $   $   $   $ (19.9 )

Level 2

    520.0     (45.8 )   196.8     99.9     (16.1 )   (0.4 )   (0.6 )   753.8  

Level 3

    312.7     343.9     147.4     (38.8 )   (11.2 )   2.9     (4.9 )   752.0  
   

Total net derivative asset (liability) subject to mark-to-market accounting

  $ 812.8   $ 298.1   $ 344.2   $ 61.1   $ (27.3 ) $ 2.5   $ (5.5 ) $ 1,485.9  
   

        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. 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. 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 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 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).

        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, many contracts are direct contracts between market participants and are not exchange-traded or financially settling contracts that can be readily offset 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.

        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 preceding table. However, based upon the nature of our Global Commodities 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. Generally, we do not expect to realize the value of these contracts and related hedges by selling or assigning the contracts themselves in total.

Operating Expenses

Our merchant energy business operating expenses decreased $62.1 million during 2008 compared to 2007 mostly due to lower performance-based labor and benefit costs at our merchant energy business of $129.2 million, partially offset by higher non-labor operating expenses of $67.1 million, which included approximately $32 million of higher bad debt expense.

        Our merchant energy business operating expenses increased $242.4 million during 2007 compared to 2006 mostly due to an increase at our Global Commodities and Customer Supply operations totaling $218.4 million, primarily related to the continued growth of this operation and higher compensation and benefit costs.

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Impairments and Other Costs

Our impairments and other costs are discussed in more detail in Note 2 to Consolidated Financial Statements.

Workforce Reduction Costs

Our merchant energy business recognized expenses associated with our workforce reduction efforts as discussed in more detail in Note 2 to Consolidated Financial Statements.

Merger Termination and Strategic Alternatives Costs

We discuss costs related to the terminated merger with MidAmerican, the conversion of the Series A Preferred Stock, the Investment Agreement with EDF and our pursuit of other strategic alternatives in Note 2 to Consolidated Financial Statements.

Depreciation, Depletion and Amortization Expense

Merchant energy depreciation, depletion, and amortization expenses increased $17.2 million in 2008 compared to 2007 mostly due to increased depletion expenses related to our upstream natural gas operations as a result of increased drilling and production, partially offset by the cessation of operations at our synfuel facilities in December 2007.

        Merchant energy depreciation, depletion, and amortization expenses increased $11.2 million in 2007 compared to 2006 mostly due to:

    $30.9 million related to our upstream natural gas operations, primarily due to acquisitions made in 2007, and
    $6.2 million primarily related to additions to our nuclear facilities, including the impact of the uprate at our Ginna facility in 2006.

        These increases were partially offset by $29.0 million primarily related to the absence of depreciation associated with the gas plants that were sold in December 2006.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $14.1 million in 2008 compared to 2007, primarily due to $9.8 million in higher property and franchise taxes at our Generation operation, $2.9 million of higher gross receipts taxes at our retail customer supply operation, and $1.4 million of higher production taxes related to our upstream gas producing properties.

        Taxes other than income taxes decreased $9.8 million in 2007 compared to 2006, primarily due to $5.8 million lower gross receipts tax at our retail customer supply operation and a $4.2 million decrease due to the sale of our gas-fired plants.

Gains on Sale of Assets

During 2008, we recognized net gains of $25.5 million, including a $14.3 million gain, net of the minority interest gain of $0.7 million, related to the sale of our working interests in oil and natural gas producing wells in Oklahoma to Constellation Energy Partners that was completed in the first quarter of 2008.

        We discuss our gains on sale of assets in more detail in Note 2 to Consolidated Financial Statements.

Regulated Electric Business

Our regulated electric business is discussed in detail in Item 1. Business—Electric Business section.

Results

 
  2008
  2007
  2006
 
   
 
  (In millions)
 

Revenues

  $ 2,679.7   $ 2,455.7   $ 2,115.9  

Electricity purchased for resale expenses

    (1,880.1 )   (1,500.4 )   (1,167.8 )

Operations and maintenance expenses

    (380.5 )   (376.1 )   (351.3 )

Workforce reduction costs

    (4.6 )        

Merger termination and strategic alternatives costs *

            (3.3 )

Depreciation and amortization

    (184.2 )   (187.4 )   (181.5 )

Taxes other than income taxes

    (139.1 )   (140.2 )   (134.9 )
   

Income from Operations

  $ 91.2   $ 251.6   $ 277.1  
   

Net Income

  $ 1.1   $ 97.9   $ 120.2  
   

Other Items Included in Operations (after-tax):

                   
 

Maryland settlement credit

  $ (126.5 ) $   $  
 

Effective tax rate impact of Maryland settlement agreement

    16.0          
 

Workforce reduction costs

    (2.8 )        
 

Merger termination and strategic alternatives costs *

            (0.8 )
   

Total Other Items

  $ (113.3 ) $   $ (0.8 )
   

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

*
Costs allocated to the regulated electric business during 2008 prior to the transaction with EDF have been allocated to the merchant energy segment.

        Net income from the regulated electric business decreased $96.8 million in 2008 compared to 2007, primarily due to the impact of the Maryland settlement credit of $126.5 million after-tax, partially offset by the impact on the effective tax rate of the Maryland settlement credit of $16.0 million and reduced depreciation and amortization expense of $2.0 million after-tax.

        Net income from the regulated electric business decreased $22.3 million in 2007 compared to 2006, primarily due to the following:

    increased operations and maintenance expenses of $15.0 million after-tax mostly due to higher labor and benefits costs,
    increased depreciation and amortization of $3.6 million after-tax, and
    increased taxes other than income taxes of $3.2 million after-tax.

        The decrease was partially offset by an increase in revenues less electricity purchased for resale expenses of $4.4 million after-tax, which includes the impact of Senate Bill 1 credits.

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Electric Revenues

The changes in electric revenues in 2008 and 2007 compared to the respective prior year were caused by:

 
  2008
  2007
 
   
 
  (In millions)
 

Distribution volumes

  $ (15.0 ) $ 19.5  

Maryland settlement credit

    (189.1 )    

Revenue decoupling

    12.5      

Standard offer service

    79.4     267.8  

Rate stabilization credits

    287.3     34.6  

Rate stabilization recovery

    43.1     36.1  

Financing credits

    (9.1 )   (7.5 )

Senate Bill 1 credits

    3.3     (29.7 )
   

Total change in electric revenues from electric system sales

    212.4     320.8  

Other

    11.6     19.0  
   

Total change in electric revenues

  $ 224.0   $ 339.8  
   

Distribution Volumes

Distribution volumes are the amount of electricity that BGE delivers to customers in its service territory.

        The percentage changes in our electric system distribution volumes, by type of customer, in 2008 and 2007 compared to the respective prior year were:

 
  2008
  2007
 
   

Residential

    (2.6 )%   3.7 %

Commercial

    (3.6 )   3.6  

Industrial

    (6.3 )   0.2  

        In 2008, we distributed less electricity to residential and commercial customers due to milder weather and decreased usage per customer, partially offset by an increased number of customers. We distributed less electricity to industrial customers primarily due to decreased usage per customer.

        In 2007, we distributed more electricity to residential customers due to colder winter weather and an increased number of customers, partially offset by decreased usage per customer. We distributed more electricity to commercial customers due to increased usage per customer, colder winter weather, and an increased number of customers. We distributed essentially the same amount of electricity to industrial customers.

Maryland Settlement Credit

As discussed in more detail in Note 2 to Consolidated Financial Statements, BGE entered into a settlement agreement with the State of Maryland and other parties, which provided residential electric customers a credit totaling $170 per customer. The estimated settlement of $188.2 million was accrued in the second quarter of 2008 and a total of $189.1 million was credited to customers in the third and fourth quarters of 2008.

Revenue Decoupling

Beginning in 2008, the Maryland PSC allows us to record a monthly adjustment to our electric distribution revenues from residential and small commercial customers to eliminate the effect of abnormal weather and usage patterns per customer on our electric distribution volumes. This means our monthly electric distribution revenues for residential and small commercial customers are based on weather and usage that is considered "normal" for the month. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions.

Standard Offer Service

BGE provides standard offer service for customers that do not select an alternative supplier. We discuss the provisions of Maryland's Senate Bill 1 related to residential electric rates in the Business Environment—Regulation—Maryland—Senate Bills 1 and 400 section.

        Standard offer service revenues increased in 2008 compared to 2007 mostly due to higher standard offer service rates, partially offset by lower standard offer service volumes.

        Standard offer service revenues increased in 2007 compared to 2006, primarily due to an increase in the standard offer service rates following the expiration of residential rate freeze service in July 2006, partially offset by lower standard offer service volumes.

Rate Stabilization Credits

As a result of Senate Bill 1, we were required to defer from July 1, 2006 until May 31, 2007 a portion of the full market rate increase resulting from the expiration of the residential rate freeze. In addition, we offered a plan also required under Senate Bill 1 allowing residential customers the option to defer the transition to market rates from June 1, 2007 until January 1, 2008.

        Revenues in 2008 increased compared to 2007 due to lower rate stabilization credits as a result of the expiration of the rate stabilization plans.

        In 2007 compared to 2006, revenues increased due to lower rate stabilization credits provided to residential electric customers as a result of the end of the first deferral period on May 31, 2007, partially offset by the additional deferrals during the second deferral period, which ended on December 31, 2007.

Rate Stabilization Recovery

In late June 2007, BGE began recovering amounts deferred during the first rate deferral period that ended on May 31, 2007. In April 2008, BGE began recovering amounts deferred during the second rate deferral period that ended on December 31, 2007. The recovery of the second rate deferral will occur over a 21-month period that began April 1, 2008 and ending on December 31, 2009. The recovery of the first rate stabilization plan will occur over approximately ten years.

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Financing Credits

Concurrent with the recovery of the deferred amounts related to the first rate deferral period, we are providing credits to residential customers to compensate them primarily for income tax benefits associated with the financing of the deferred amounts with rate stabilization bonds. We discuss the rate stabilization bonds in more detail in Note 9 to Consolidated Financial Statements.

Senate Bill 1 Credits

As a result of Senate Bill 1, beginning January 1, 2007, we were required to provide to residential electric customers a credit equal to the amount collected from all BGE electric customers for the decommissioning of our Calvert Cliffs Nuclear Power Plant and to suspend collection of the residential return component of the administrative charge collected through residential SOS rates through May 31, 2007. Under an order issued by the Maryland PSC in May 2007, as of June 1, 2007, we were required to reinstate collection of the residential return component of the administration charge in rates and to provide all residential electric customers a credit for the residential return component of the administrative charge. Under the Maryland settlement agreement, which is discussed in more detail in Note 2 to Consolidated Financial Statements, BGE was allowed to resume collection of the residential return portion of the administrative charge from June 1, 2008 through May 31, 2010 without having to rebate it to residential customers.

        The increase in revenues during 2008 compared to 2007 is primarily due to the absence of the credit for the residential return component of the administrative charge which was suspended under the Maryland settlement agreement, partially offset by lower distribution volumes.

Electricity Purchased for Resale Expenses

Electricity purchased for resale expenses include the cost of electricity purchased for resale to our standard offer service customers. These costs do not include the cost of electricity purchased by delivery service only customers. The following table summarizes our regulated electricity purchased for resale expenses:

 
  2008
  2007
  2006
 
   
 
  (In millions)
 

Actual costs

  $ 1,821.1   $ 1,759.2   $ 1,489.7  

Deferral under rate stabilization plan

        (287.3 )   (321.9 )

Recovery under rate stabilization plans

    59.0     28.5      
   

Electricity purchased for resale expenses

  $ 1,880.1   $ 1,500.4   $ 1,167.8  
   

Actual Costs

BGE's actual costs for electricity purchased for resale increased $61.9 million for 2008 compared to 2007, primarily due to higher contract prices to purchase electricity for our customers, partially offset by lower volumes.

        BGE's actual costs for electricity purchased for resale increased $269.5 million for 2007 compared to 2006, primarily due to higher contract prices to purchase electricity for our residential customers following the expiration of contracts that were executed in 2000 as part of the implementation of electric deregulation in Maryland, partially offset by lower volumes.

Deferral under Rate Stabilization Plan

The deferral of the difference between our actual costs of electricity purchased for resale and what we are allowed to bill customers under Senate Bill 1 ended on December 31, 2007. Since July 1, 2006, we have deferred $609.2 million in electricity purchased for resale expenses. In 2007, we deferred $287.3 million in electricity purchased for resale expenses. These deferred expenses, plus carrying charges, are included in "Regulatory Assets (net)" in our, and BGE's, Consolidated Balance Sheets. We discuss the provisions of Senate Bill 1 related to residential electric rates in the Business Environment—Regulation—Maryland—Senate Bills 1 and 400 section.

Recovery under Rate Stabilization Plans

In late June 2007, we began recovering previously deferred amounts from customers related to our first rate stabilization plan. In April 2008, we began recovering previously deferred amounts from customers related to our second rate stabilization plan. We recovered $59.0 million in 2008 and $28.5 million in 2007 in deferred electricity purchased for resale expenses. These collections secure the payment of principal and interest and other ongoing costs associated with rate stabilization bonds issued by a subsidiary of BGE in June 2007.

Electric Operations and Maintenance Expenses

Regulated electric operations and maintenance expenses increased $4.4 million in 2008 compared to 2007 mostly due to increased uncollectible accounts receivable expense of $14.2 million, partially offset by $9.0 million of lower labor and benefit costs.

        Regulated operations and maintenance expenses increased $24.8 million in 2007 compared to 2006 mostly due to higher labor and benefit costs and the impact of inflation on other costs of $16.9 million, customer education in relation to rate stabilization of $5.3 million, and increased uncollectible accounts receivable expense of $2.9 million.

Workforce Reduction Costs

During the fourth quarter of 2008, we executed a restructuring of the workforce. We recognized a $4.6 million pre-tax charge in 2008 related to this reduction in force.

        We incurred no workforce reduction costs in 2007 or 2006.

Electric Depreciation and Amortization Expense

Regulated electric depreciation and amortization expense decreased $3.2 million in 2008 compared to 2007, primarily due to $10.0 million in lower depreciation expense as a result of revised depreciation rates which were implemented on June 1, 2008 for regulatory and financial reporting purposes as part of the Maryland settlement agreement. The Maryland settlement agreement is discussed in more detail in Note 2 to Consolidated

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Financial Statements. This decrease was partially offset by additional property placed in service in 2008.

        Regulated electric depreciation and amortization expense increased $5.9 million in 2007 compared to 2006, primarily due to additional property placed in service.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $5.3 million in 2007 in comparison with 2006, primarily due to increased property taxes.

Regulated Gas Business

Our regulated gas business is discussed in detail in Item 1. Business—Gas Business section.

Results

 
  2008
  2007
  2006
 
   
 
  (In millions)
 

Revenues

  $ 1,024.0   $ 962.8   $ 899.5  

Gas purchased for resale expenses

    (694.5 )   (639.8 )   (581.5 )

Operations and maintenance expenses

    (157.3 )   (157.5 )   (144.8 )

Workforce reduction costs

    (1.8 )        

Merger termination and strategic alternatives costs *

            (1.4 )

Depreciation and amortization

    (43.7 )   (46.8 )   (46.0 )

Taxes other than income taxes

    (35.4 )   (36.1 )   (33.8 )
   

Income from Operations

  $ 91.3   $ 82.6   $ 92.0  
   

Net Income

  $ 37.2   $ 28.8   $ 37.0  
   

Other Items Included in Operations (after-tax):

                   
 

Workforce reduction costs

  $ (1.0 ) $   $  
 

Merger termination and strategic alternatives costs *

            (0.4 )
   

Total Other Items

  $ (1.0 ) $   $ (0.4 )
   

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

*
Costs allocated to the regulated gas business during 2008 prior to the transaction with EDF have been allocated to the merchant energy segment.

Net income from the regulated gas business increased $8.4 million in 2008 compared to 2007, primarily due to an increase in revenues less gas purchased for resale expenses of $4.0 million after-tax and reduced depreciation and amortization expense of $1.9 million after-tax.

        Net income from the regulated gas business decreased $8.2 million in 2007 compared to 2006, primarily due to increased operations and maintenance expenses of $7.7 million after-tax.

Gas Revenues

The changes in gas revenues in 2008 and 2007 compared to the respective prior year were caused by:

 
  2008
  2007
 
   
 
  (In millions)
 

Distribution volumes

  $ (5.1 ) $ 19.3  

Base rates

    (0.1 )   0.2  

Revenue decoupling

    6.2     (20.1 )

Gas cost adjustments

    20.3     74.4  
   

Total change in gas revenues from gas system sales

    21.3     73.8  

Off-system sales

    40.3     (11.2 )

Other

    (0.4 )   0.7  
   

Total change in gas revenues

  $ 61.2   $ 63.3  
   

Distribution Volumes

The percentage changes in our distribution volumes, by type of customer, in 2008 and 2007 compared to the respective prior year were:

 
  2008
  2007
 
   

Residential

    (3.9 )%   17.7 %

Commercial

    (3.1 )   14.6  

Industrial

    2.8     (11.3 )

        In 2008, we distributed less gas to residential customers and commercial customers due to decreased usage per customer, partially offset by an increased number of customers. We distributed more gas to industrial customers mostly due to increased usage per customer, partially offset by a decreased number of customers.

        In 2007, we distributed more gas to residential customers due to colder weather, increased usage per customer and an increased number of customers. We distributed more gas to commercial customers due to an increased number of customers and colder weather, partially offset by decreased usage per customer. We distributed less gas to industrial customers mostly due to decreased usage per customer.

Revenue Decoupling

The Maryland PSC allows us to record a monthly adjustment to our gas distribution revenues to eliminate the effect of abnormal weather and usage patterns per customer on our gas distribution volumes. This means our monthly gas distribution revenues are based on weather and usage that is considered "normal" for the month. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions.

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Gas Cost Adjustments

We charge our gas customers for the natural gas they purchase from us using gas cost adjustment clauses set by the Maryland PSC as described in Note 1 to Consolidated Financial Statements. However, under the market-based rates mechanism approved by the Maryland PSC, 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.

        Customers who do not purchase gas from BGE are not subject to the gas cost adjustment clauses because we are not selling gas to them. However, these customers are charged base rates to recover the costs BGE incurs to deliver their gas through our distribution system, and are included in the gas distribution volume revenues.

        Gas cost adjustment revenues increased in 2008 compared to 2007 because we sold gas at higher prices, partially offset by less gas sold.

        Gas cost adjustment revenues increased in 2007 compared to 2006 because we sold more gas at higher prices.

Off-System Sales

Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Off-system gas sales, which occur after BGE has satisfied its customers' demand, are not subject to gas cost adjustments. The Maryland PSC approved an arrangement for part of the margin from off-system sales to benefit customers (through reduced costs) and the remainder to be retained by BGE (which benefits shareholders). Changes in off-system sales do not significantly impact earnings.

        Revenues from off-system gas sales increased in 2008 compared to 2007 because we sold gas at higher prices, partially offset by less gas sold.

        Revenues from off-system gas sales decreased in 2007 compared to 2006 because we sold gas at lower prices, partially offset by more gas sold.

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 only customers.

        Gas costs increased $54.7 million in 2008 compared to 2007 because we purchased gas at higher prices, partially offset by lower volumes.

        Gas costs increased $58.3 million in 2007 compared to 2006 because we purchased more gas, partially offset by lower prices.

Gas Operations and Maintenance Expenses

Regulated gas operations and maintenance expenses increased $12.7 million in 2007 compared to 2006 mostly due to higher labor and benefit costs and the impact of inflation on other costs of $8.9 million and increased uncollectible accounts receivable expense of $1.2 million.

Gas Workforce Reduction Costs

During the fourth quarter of 2008, we executed a restructuring of the workforce at our operations. We recognized a $1.8 million pre-tax charge in 2008 related to this reduction in force.

        We incurred no workforce reduction costs in 2007 or 2006.

Gas Depreciation and Amortization

Regulated gas depreciation and amortization expense decreased $3.1 million in 2008 compared to 2007, primarily due to $3.5 million in lower depreciation expense as a result of revised depreciation rates which were implemented on June 1, 2008 for regulatory and financial reporting purposes as part of the Maryland settlement agreement. The Maryland settlement agreement is discussed in more detail in Note 2 to Consolidated Financial Statements.

Gas Taxes Other Than Income Taxes

Gas taxes other than income taxes increased $2.3 million in 2007 compared to 2006, primarily due to increased property taxes.

Other Nonregulated Businesses

Results

 
  2008
  2007
  2006
 
   
 
  (In millions)
 

Revenues

  $ 253.4   $ 249.8   $ 231.0  

Operating expenses

    (178.2 )   (173.5 )   (173.1 )

Merger termination and strategic alternatives costs

            (0.5 )

Workforce reduction costs

    (0.4 )        

Depreciation and amortization

    (68.2 )   (53.7 )   (37.7 )

Taxes other than income taxes

    (3.0 )   (2.4 )   (2.0 )
   

Income from Operations

  $ 3.6   $ 20.2   $ 17.7  
   

Income from continuing operations and before cumulative effects of changes in accounting principles (after-tax)

  $ 4.7   $ 16.5   $ 11.3  
 

Income from discontinued operations (after-tax)

            0.9  
   

Net Income

  $ 4.7   $ 16.5   $ 12.2  
   

Other Items Included In Operations (after-tax):

                   
 

Merger termination and strategic alternatives costs

  $   $   $ (0.2 )
 

Workforce reduction costs

    (0.3 )        
   
 

Total Other Items

  $ (0.3 ) $   $ (0.2 )
   

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 decreased $11.8 million in 2008 compared to 2007 primarily because the first quarter of 2007 included a gain related to a sale of a leasing arrangement that did not occur in 2008 and due to increased depreciation and amortization of $8.7 million after-tax.

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        Net income from our other nonregulated businesses increased $4.3 million in 2007 compared to 2006, primarily due to higher construction volume at our energy projects business and a gain related to a sale of a leasing arrangement, partially offset by increased depreciation and amortization of $9.5 million after-tax.

Consolidated Nonoperating Income and Expenses

Gains on Sale of CEP Equity

Gains on sale of CEP equity decreased $63.3 million for the year ended December 31, 2008 as CEP, an equity investment of Constellation Energy, did not sell additional equity in 2008 as it had during 2007.

        In November 2006, CEP completed an initial public offering of 5.2 million common units at $21 per unit. As a result of the initial public offering of CEP, we recognized a pre-tax gain of $28.7 million. As a result of subsequent sales of equity by CEP, which reduced our relative ownership percentage, we recognized pre-tax gains totaling $63.3 million in 2007. We discuss the issuances of CEP equity in more detail in Note 2 to Consolidated Financial Statements.

Other (Expense) Income

In 2008, we had other expenses of $52.3 million and, in 2007 we had other income of $158.6 million. The $210.9 million decrease in 2008 compared to 2007 is mostly due to lower interest and investment income as a result of a lower average cash balance of approximately $850 million and an increase in other-than-temporary impairment charges related to our nuclear decommissioning trust fund assets of $156.5 million.

        Other income at BGE increased $2.8 million in 2008 compared to 2007 primarily due to an increase in equity funds capitalized on increased construction work in progress in 2008.

        Other income increased $92.5 million in 2007 compared to 2006, mostly due to higher interest and investment income due to a higher cash balance.

        Total other income at BGE increased $20.8 million in 2007 compared to 2006, primarily due to carrying charges related to rate stabilization deferrals of "Electricity Purchased for Resale" expense. We discuss the rate stabilization deferrals in more detail in the Regulated Electric Business section.

Fixed Charges

Fixed charges increased $56.7 million in 2008 compared to 2007 mostly due to a higher level of interest expense associated with the new debt issuances and higher amortization of debt issuance and credit facility costs.

        Fixed charges at BGE increased $14.6 million in 2008 compared to 2007 mostly due to a higher level of interest expense associated with the new debt issuances and higher amortization of debt issuance and credit facility costs.

        Fixed charges decreased $23.1 million in 2007 compared to 2006, mostly due to a lower average level of debt outstanding.

        Fixed charges at BGE increased $22.7 million in 2007 compared to 2006 mostly due to interest expense recognized on debt that was issued in October 2006 and the rate stabilization bonds issued in June 2007.

Income Taxes

Our income tax expense decreased $506.6 million during 2008 compared to 2007 mostly due to a decrease in income before income taxes, which included approximately $1.2 billion of non-tax deductible merger termination and strategic alternatives costs, partially offset by the absence of synthetic fuel tax credits, which expired in 2007.

        BGE's income tax expense decreased $75.3 million during 2008 compared to 2007 primarily due to lower pre-tax income as a result of the $189 million Maryland settlement credit recorded in 2008. We discuss the Maryland settlement agreement in more detail in Note 2 to Consolidated Financial Statements.

        Our income taxes increased $77.3 million in 2007 compared to 2006 mostly because of an increase in pre-tax income and a decrease in synthetic fuel tax credits of $20 million.

        In 2007, the State of Maryland increased its corporate income tax rate from 7% to 8.25%, effective January 1, 2008. The impact of adjusting all existing deferred income tax assets and liabilities for this change in the period of enactment was not material to us. However, this did impact BGE, as discussed below.

        Income taxes at BGE decreased $6.2 million in 2007 compared to 2006, primarily due to lower pre-tax income partially offset by the increase in the Maryland state tax rate.

Defined Benefit Plans Expense and Funded Status

Our actual return on qualified pension plan assets for the purpose of computing annual net periodic pension cost in accordance with SFAS No. 87, Employers' Accounting for Pensions was a loss of 29.5% during 2008 as compared to our assumption of an expected annual return on pension plan assets of 8.75%. This loss reflects the substantial declines in financial markets experienced through 2008. As disclosed in Note 7 to Consolidated Financial Statements, we determine the expected return on pension plan assets component of our annual pension expense using a market-related value of pension plan assets that recognizes asset gains and losses over a five-year period. As a result of the losses incurred during 2008, our annual pension expense will increase beginning in 2009. Also, the lower fair value of our pension plan assets increased our unfunded pension obligation at December 31, 2008 and the related after-tax charge to "Accumulated other comprehensive loss" in accordance with SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans (SFAS No. 158).

        In addition to the losses experienced on our pension plan assets during 2008, there has also been a decrease in the discount rate we use to determine our defined benefit plan liabilities. At December 31, 2008, our discount rate assumption decreased to 6.00% from 6.25% in the prior year as a result of a decrease in interest rates. This will increase our pension and postretirement benefits expense beginning in 2009 and resulted in an increase in our unfunded obligation for those plans at December 31, 2008.

        We disclose the SFAS No. 158 funded status adjustment at December 31, 2008, in Note 7 to Consolidated Financial

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Statements. In addition, effective January 1, 2009, we are reducing our expected annual return on pension plan assets from 8.75% to 8.50% based on updated analyses of projected future asset returns. As a result of the losses experienced on our qualified pension plan assets during 2008 and the reductions to our expected annual return on pension plan assets and discount rate assumptions, we expect our annual defined benefit plans cost will be higher by approximately $15 million pre-tax, for the next five years. In connection with the decline in our qualified pension plan funded status at December 31, 2008, we also expect to increase our annual qualified pension plan contributions from the $76 million we contributed in 2008 to an average level of approximately $180 million per year over the next five years. These expectations about future cost and funding levels are subject to material revision based on numerous factors including actual pension asset returns, future interest rate levels, impact of available liquidity on amount and timing of contributions, potential changes in regulatory requirements, plan design amendments, and demographic experience.

Allowance for Uncollectible Accounts Receivable

Our allowance for uncollectible accounts receivable increased $195.7 million from $44.9 million at December 31, 2007 to $240.6 million at December 31, 2008, related to our merchant energy business and regulated electric and gas businesses.

        The increase in allowance for uncollectible accounts receivable from our merchant energy business was a result of counterparties with financial difficulties. The regulated electric and gas allowance for uncollectible accounts receivable increased $13.0 million in 2008 compared to 2007, mostly due to increased customer bills caused by higher standard offer service rates and the decreased ability of customers to pay their utility bills as a result of the economic downturn.

        If the current economic recession continues on a prolonged basis, our and BGE's bad debt expense could increase in the future despite our efforts to mitigate those risks. We discuss our credit risk in more detail in the Risk Management section.

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Financial Condition

Cash Flows

The following table summarizes our 2008 cash flows by business segment, as well as our consolidated cash flows for 2008, 2007, and 2006.

 
  2008 Segment Cash Flows    
   
   
 
 
   
   
  Holding Company and Other
  Consolidated Cash Flows  
 
  Merchant
  Regulated
  2008
  2007
  2006
 
   
 
  (In millions)
 

Operating Activities

                                     
 

Net (loss) income

  $ (1,357.4 ) $ 38.3   $ 4.7   $ (1,314.4 ) $ 821.5   $ 936.4  
 

Non-cash merger termination and strategic alternatives costs

    541.8             541.8          
 

Other non-cash adjustments to net (loss) income

    816.8     334.2     48.4     1,199.4     545.4     223.6  
 

Changes in working capital

                                     
   

Derivative assets and liabilities, excluding collateral

    (750.5 )   (2.0 )   (5.4 )   (757.9 )   (138.2 )   (286.1 )
   

Net collateral and margin

    (962.1 )   1.8         (960.3 )   49.6     (630.6 )
   

Other changes

    2.9     (45.0 )   135.7     93.6     (242.4 )   239.0  
 

Defined benefit obligations (1)

                (20.8 )   (53.6 )   40.5  
 

Other

    (6.1 )   (35.1 )   (14.5 )   (55.7 )   (54.5 )   2.5  
   

Net cash (used in) provided by operating activities

    (1,714.6 )   292.2     168.9     (1,274.3 )   927.8     525.3  
   

Investing Activities

                                     
 

Investments in property, plant and equipment

    (1,425.1 )   (421.5 )   (87.5 )   (1,934.1 )   (1,295.7 )   (962.9 )
 

Asset acquisitions and business combinations, net of cash acquired

    (309.8 )       (5.5 )   (315.3 )   (347.5 )   (137.6 )
 

Investment in nuclear decommissioning trust fund securities

    (440.6 )           (440.6 )   (659.5 )   (492.5 )
 

Proceeds from nuclear decommissioning trust fund securities

    421.9             421.9     650.7     483.7  
 

Net proceeds from sale of gas-fired plants and discontinued operations

                        1,630.7  
 

Issuances of loans receivable

                    (19.0 )   (65.4 )
 

Sale of investments and other assets

    432.3     12.9     1.1     446.3     13.9     43.9  
 

Contract and portfolio acquisitions

                    (474.2 )   (2.3 )
 

Decrease (increase) in restricted funds (2)

    (16.6 )   15.5     (941.7 )   (942.8 )   (109.9 )   7.7  
 

Other investments

    23.2         (1.5 )   21.7     (45.3 )   54.8  
   

Net cash (used in) provided by investing activities

    (1,314.7 )   (393.1 )   (1,035.1 )   (2,742.9 )   (2,286.5 )   560.1  
   

Cash flows from operating activities less cash flows from investing activities

  $ (3,029.3 ) $ (100.9 ) $ (866.2 )   (4,017.2 )   (1,358.7 )   1,085.4  
           

Financing Activities (1)

                                     
 

Net issuance (repayment) of debt (includes $1 billion proceeds from MidAmerican and $1 billion proceeds from EDF)

                      3,447.7     (33.1 )   242.2  
 

Debt issuance costs

                      (104.8 )        
 

Proceeds from issuance of common stock

                      17.6     65.1     84.4  
 

Common stock dividends paid

                      (336.3 )   (306.0 )   (264.0 )
 

Reacquisition of common stock

                      (16.2 )   (409.5 )    
 

Proceeds from initial public offering of CEP

                              101.3  
 

Proceeds from contract and portfolio acquisitions

                          847.8     221.3  
 

Other

                      115.5     1.2     5.5  
                         

Net cash provided by financing activities

                      3,123.5     165.5     390.7  
                         

Net (decrease) increase in cash and cash equivalents

                    $ (893.7 ) $ (1,193.2 ) $ 1,476.1  
                         
(1)
Items are not allocated to the business segments because they are managed for the company as a whole.

(2)
The increase in restricted funds at our Holding Company and Other is primarily related to $1.0 billion of restricted cash related to the issuance of Series B Preferred Stock to EDF. These funds are held at the holding company and are restricted for payment of the 14% Senior Notes held by MidAmerican. The 14% Senior Notes were repaid in full in January 2009.

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

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Cash Flows from Operating Activities

Cash used in operating activities was $1,274.3 million in 2008 compared to cash provided by operating activities of $927.8 million in 2007. This $2,202.1 million decrease in cash flows was primarily due to an increase in net collateral and margin posted, payments to MidAmerican to terminate our planned merger, payments in connection with the conversion of the Series A Preferred Stock, and credits rebated to BGE residential electric customers.

        Total net cash collateral posted in 2008 increased as follows:

   
 
  (In millions)
 

Net collateral and margin posted, December 31, 2007

  $ (485.3 )

Return of collateral held associated with nonderivative contracts

    (26.3 )

Additional collateral posted associated with nonderivative contracts *

    (330.5 )

Additional initial and variation margin posted on exchange-traded transactions recorded in accounts receivable

    (94.0 )

Additional fair value net cash collateral posted (netted against derivative assets / liabilities) **

    (509.5 )
   

Change in net collateral and margin posted

    (960.3 )
   

Net collateral and margin posted, December 31, 2008

  $ (1,445.6 )
   
*
Includes approximately $224 million of additional collateral posted due to certain counterparties that would not accept letters of credit issued by certain financial institutions.

**
We discuss our netting of fair value collateral with our derivative assets / liabilities in more detail in Note 13 to Consolidated Financial Statements.

        The $960.3 million increase in net collateral and margin posted during 2008 primarily reflects the following:

    changes in commodity prices and the level of our open positions,
    increases in amounts posted to exchanges to meet initial margin requirements and changes in the rules governing exchange margin requirements, and
    additional collateral posted following our credit rating downgrades. We discuss our security ratings in more detail below. We discuss our downgrade collateral requirements in more detail in the Collateral section.

        We discuss all forms of collateral in terms of their impact on our net available liquidity in the Available Sources of Funding section.

        The remaining unfavorable change in cash used in operating activities in 2008 compared to 2007 was primarily due to the following:

    $663.0 million use of cash, consisting of $175 million paid to MidAmerican related to the termination of the merger, $418 million paid to MidAmerican for settling a portion of the conversion of the Series A Preferred Stock in cash, and $70 million paid to various parties for merger and other strategic alternatives costs,