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

FORM 10-K

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

For the fiscal year ended DECEMBER 31, 2009

2 CENTER PLAZA, 110 WEST FAYETTE STREET,             BALTIMORE, MARYLAND                21202
(Address of principal executive offices)                                                                                                   (Zip Code)

410-234-5000
(Registrants' telephone number, including area code)

MARYLAND
(States of incorporation of both registrants)

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

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

        Indicate by check mark 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. has submitted electronically and posted on its corporate Web-site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o

        Indicate by check mark whether Baltimore Gas and Electric Company has submitted electronically and posted on its corporate Web-site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o    No 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, 2009 was approximately $5,309,415,341 based upon New York Stock Exchange composite transaction closing price.

CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE
201,091,187 SHARES OUTSTANDING ON JANUARY 29, 2010.

DOCUMENTS INCORPORATED BY REFERENCE

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

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Forward Looking Statements

We make statements in this report that are considered forward looking statements within the meaning of the Securities Exchange Act of 1934. Sometimes these statements will contain words such as "believes," "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, and emission allowances, and the impact of such changes on our liquidity requirements,

•

the liquidity and competitiveness of wholesale and retail 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,

•

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, including generating facilities and new nuclear generation development projects,

•

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,

•

regulatory or legislative developments federally, in Maryland, or in other states that affect energy deregulation, the price of energy, transmission or distribution rates and revenues, demand for energy, or increases in costs, including costs related to 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 and BGE's transmission and distribution facilities, including 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 impact of industry consolidation,

•

the impact of increased energy conservation and use of renewable energy,

•

the actual outcome of uncertainties associated with assumptions and estimates requiring judgment when managing our business, 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, owns interests in, and operates electric generation facilities located in various regions of the United States. Our merchant energy business also 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 energy performance contracting and energy efficiency engineering services,

•

provide home improvements, service heating, air conditioning, plumbing, electrical, and indoor air quality systems, provide natural gas marketing to residential customers in central Maryland, and, in 2010, began providing residential electric supply, and

•

develop and deploy new nuclear plants in North America through our joint venture (UniStar Nuclear Energy, LLC) with a subsidiary of EDF Group.

        On November 6, 2009, we completed the sale of a 49.99% membership interest in Constellation Energy Nuclear Group LLC and affiliates (CENG), our nuclear generation and operation business, to EDF Group and affiliates (EDF) for total consideration of approximately $4.7 billion ($4.5 billion at close plus expense reimbursements). Our remaining 50.01% investment in CENG is an integral part of our nuclear business.

        In connection with closing the transaction with EDF, we and EDF agreed to comply with certain conditions contained in an order from the Maryland Public Service Commission (Maryland PSC). We discuss these conditions in detail in Item 7. Management's Discussion and Analysis—Business Environment—Regulation—Maryland.

        Prior to 2009, our merchant energy business included significant trading operations and an international commodities operation and 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.

        Therefore, as a capital- and asset-intensive business, Constellation Energy was significantly impacted by the events in the financial and credit markets during 2008. To address the liquidity issues arising from the credit and market events of 2008, we explored a series of strategic initiatives to improve our liquidity and reduce our business risk. During 2009, we completed transactions to sell our international commodities operation, our gas trading operation, our shipping joint venture, and our uranium market participant. These transactions helped improve our liquidity and reduce our business risk and resulted in substantial changes to our business in 2009. We discuss these transactions in more detail in Note 2 to Consolidated Financial Statements.

        We plan to execute the following objectives that we believe will strengthen the Company:

•

continuing a disciplined approach to the management of collateral and liquidity, including:

•

pricing new retail and wholesale business to reflect the full cost of capital in the current economic environment,

•

balancing operating cash flows with earnings growth,

•

maintaining a liquidity cushion in excess of credit-rating downgrade collateral requirements, and

•

aligning our load obligations by buying generation assets in regions where we do not have a significant generation presence,

•

focusing on Constellation Energy's core strengths of:

•

owning, developing, and operating 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,

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maintaining credit metrics consistent with investment grade ratings.

        We believe that focusing on 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—Strategy.

Operating Segments

The percentages of revenues, net income (loss) attributable to common stock, 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.

 

 

(1)

Excludes income from discontinued operations in 2007 as discussed in more detail in Item 8. Financial Statements and Supplementary Data.

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 the United States and Canada.

        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, a fuel processing facility and power projects in the United States,

•

a nuclear generation operation that owns, operates, and maintains nuclear generating facilities (through November 6, 2009),

•

nuclear generation operations through our membership interest in CENG, our nuclear joint venture (subsequent to November 6, 2009),

•

a customer supply operation that primarily provides products and services to meet the energy requirements of wholesale and retail customers, including distribution utilities, cooperatives, aggregators, and commercial, industrial and governmental customers, and

•

a commodities operation that manages contractually controlled physical assets, including generation facilities and natural gas properties, provides risk management services, and trades energy and energy-related commodities to facilitate portfolio management.

        During 2009, our merchant energy business:

•

supplied approximately 121 million megawatt hours (MWH) of aggregate load to distribution utilities, municipalities, and commercial, industrial, and governmental customers,

•

provided approximately 350 million British Thermal Units (mmBTUs) of natural gas to commercial, industrial, and governmental customers,

•

delivered approximately 13.5 million tons of coal to international and domestic third party customers and to our own fleet (we sold our international coal operations in the first quarter of 2009), and

•

managed 7,118 megawatts (MW) of generation capacity as of December 31.

        During 2009 and prior, 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, and upstream natural gas activities.

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2010 Segments

As a result of our strategic initiatives completed in 2009 and the transformation of our business, our merchant energy business will become two separate reportable segments in 2010: Generation and Customer Supply.

        Generation will consist of all of our generating assets, which include:

•

a power generation and development operation that owns, operates, and maintains fossil and renewable generating facilities, a fuel processing facility, qualifying facilities, and power projects in the United States,

•

an operation that manages certain contractually owned physical assets, including generating facilities,

•

an interest in a nuclear generation joint venture that owns, operates, and maintains five nuclear generating units, and

•

an interest in a joint venture to develop, own, and operate new nuclear projects in the United States.

        Customer Supply will consist of the following:

•

full requirements load-serving sales of energy and capacity to utilities, cooperatives, and commercial, industrial, and governmental customers,

•

sales of retail energy products and services to commercial, industrial, and governmental customers,

•

structured transactions and risk management services for various customers (including hedging the output from generating facilities and fuel costs) and trades energy and energy-related commodities to facilitate portfolio management,

•

risk management services for our generation fleet assets,

•

design, construction, and operation of renewable energy, heating, cooling, and cogeneration facilities for commercial, industrial, and governmental customers throughout North America, including energy performance contracting and energy efficiency engineering services,

•

upstream (exploration and production) natural gas activities, and

•

sales of home improvements, servicing of electric and gas appliances, and heating, air conditioning, plumbing, electrical, and indoor air quality systems, and providing electric and natural gas to residential customers in central Maryland.

Generation

We develop, own, operate, and maintain fossil and renewable generating facilities, hold a 50.01% interest in a nuclear joint venture that owns nuclear generating facilities, and hold interests in qualifying facilities, and power projects in the United States and Canada totaling 7,118 MW. The output of our owned and contractually-controlled plants is managed by our Global Commodities operation and is hedged through a combination of power sales to wholesale and retail market participants. We also provide operation and maintenance services, including testing and start-up, to owners of electric generating facilities. Our merchant energy business meets the load-serving requirements under 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.

Investment in Nuclear Generating Facilities

On November 6, 2009, we completed the sale of a 49.99% membership interest in CENG, our subsidiary that owns our nuclear generating facilities described below. The total output of these nuclear facilities over the past three years is presented in the following table:

(1)

Represents our and CENG's (after November 6, 2009) proportionate ownership interest

         In connection with the closing of the transaction with EDF, on November 6, 2009, we entered into a power purchase agreement (PPA) with CENG, Under the terms of the PPA, we will purchase up to 90% of the output of CENG's nuclear plants that is not sold to third parties under pre-existing agreements over the five-year term of the PPA. We discuss this PPA in more detail in Note 16 to Consolidated Financial Statements.

Calvert Cliffs

CENG owns 100% of Calvert Cliffs Unit 1 and Unit 2. 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

CENG owns 100% of Nine Mile Point Unit 1 and 82% of Unit 2. 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. The Nine Mile Point Unit 1 power purchase agreement with the former plant's owners ended in August 2009.

        Nine Mile Point Unit 2 sells 90% of the plant's output to the former owners of the plant at an average

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price of nearly $35 per MWH under a PPA that terminates in November 2011. The PPA is 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 the output of Nine Mile Point Unit 2 is managed by CENG and sold into the wholesale market.

        After termination of the Nine Mile Point Unit 2 PPA, a revenue sharing agreement with the former owners of the plant will begin and continue through November 2021. Under this agreement, which applies only to CENG's 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 Unit 2.

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

Ginna

CENG owns 100% of the Ginna nuclear facility. Ginna entered service in 1970 and is licensed to operate until 2029. Ginna sells approximately 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 PPA. The remaining 10% of the output of Ginna is managed by CENG and sold into the wholesale market.

Qualifying Facilities and Power Projects

We hold up to a 50% voting interest in 18 operating energy projects, totaling approximately 771 MW, 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 2009, our wholesale customer supply operation served approximately 65 million peak MWHs of wholesale full requirements load-serving products. During 2009, our retail customer supply activities served approximately 56 million MWHs of peak load and approximately 350 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' requirements, our merchant energy business obtains energy from various sources, including:

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our generation assets,

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our leased generation assets,

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exchange-traded and bilateral power and natural gas purchase agreements,

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unit contingent power purchases from generation companies,

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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.

Global Commodities

Our Global Commodities operation manages contractually owned physical assets, including generation facilities, and natural gas properties, provides risk management 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). During 2009, we reduced our participation in the coal, freight, and gas trading markets through the

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completion of the divestitures of our international commodities and Houston-based gas trading operations. We discuss our 2009 divestitures in more detail in Note 2 to Consolidated Financial Statements.

Energy Investments

Our Global Commodities operation has investments in energy assets that primarily include natural gas activities. During 2009, we sold our previous investments in coal sourcing activities as well as our interest in dry bulk cargo vessels. We discuss each of these investments below.

Coal and International Services

We participated in global coal sourcing activities by providing coal and coal-related logistical services for the variable or fixed supply needs of global customers. We sold this operation in March 2009. We also owned a 50% interest in a shipping joint venture that owned and operated five freight ships for the delivery of coal and other dry bulk freight products. We sold our 50% interest in this shipping joint venture to our partner during 2009.

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 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. We no longer have any active involvement in the day-to-day operations of CEP. Our Houston-based downstream activities included providing natural gas to various customers, including large utilities, commercial and industrial customers, power generators, wholesale marketers, and retail aggregators. We sold our Houston-based downstream activities during 2009.

Portfolio Management and Trading

Our Global Commodities operation transacts in energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions. We use economic value at risk, which measures the market risk in our total portfolio, encompassing all aspects of our merchant energy business, along with daily value at risk, stop loss limits, position limits, generation hedge ratios, and liquidity guidelines to restrict the level of risk in our portfolio.

        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:

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manage and hedge its fixed-price energy purchase and sale commitments,

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provide fixed-price energy commitments to customers and suppliers,

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reduce exposure to the volatility of market prices, and

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hedge fuel requirements at our non-nuclear generation facilities.

        We discuss the impact of our trading activities and economic 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

•

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).

        Beginning in the fourth quarter of 2008 and continuing throughout 2009, we reduced the risk and scale of our portfolio management and trading activities. Energy trading activities were scaled back and are being used primarily for hedging our generation assets and Customer Supply operations, price discovery and verification, and for deploying limited risk capital. These efforts materially impacted our portfolio management and trading activities' contribution to our operating results.

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Fuel Sources

Our power plants use diverse fuel sources. Our fuel mix based on capacity owned at December 31, 2009 and owned generation based on actual output by fuel type in 2009 were as follows:

(1)

Reflects our 100% ownership through November 6, 2009 and 50.01% ownership from November 6, 2009 through December 31, 2009 following the sale of a 49.99% membership interest in our nuclear business on November 6, 2009.

(2)

Includes solar, geothermal, hydro, waste coal, and biomass.

(3)

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

CENG, our nuclear joint venture with EDF, owns the Calvert Cliffs, Nine Mile Point, and Ginna nuclear generating facilities.

        The supply of fuel for these nuclear generating facilities includes the:

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purchase of uranium (concentrates and uranium hexafluoride),

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conversion of uranium concentrates to uranium hexafluoride,

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enrichment of uranium hexafluoride (enrichment services and enriched uranium hexafluoride), and

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fabrication of nuclear fuel assemblies.

        CENG has commitments that provide for quantities of uranium, conversion, enrichment, and fabrication of fuel assemblies to substantially meet expected requirements for the next several years at these nuclear generating facilities.

        The uranium markets are competitive, and while prices can be volatile, CENG does not anticipate problems in meeting its 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, CENG is a party to contracts with the DOE to provide for disposal of spent nuclear fuel from our nuclear generating plants. The NWPA and CENG's 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. Through November 6, 2009, we paid those fees into the DOE's Nuclear Waste Fund and, for the remainder of 2009, CENG has paid these fees for the Calvert Cliffs, Nine Mile Point and Ginna nuclear generating facilities. The NWPA and CENG's 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 CENG undertake additional actions and incur costs to provide on-site fuel storage at its 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. We are entitled to any funds received from the DOE that reimburse any costs expended prior to the closing of the transaction with EDF for the storage of spent nuclear fuel. Any other funds received from the DOE representing the default by the DOE shall belong to CENG.

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 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 2036. Nine Mile Point and Ginna are developing independent spent fuel storage installations at each of those facilities, which are expected 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.

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Cost for Decommissioning Nuclear Facilities

When Constellation Energy sold a 49.99% membership interest in CENG on November 6, 2009, we deconsolidated CENG for financial reporting purposes and, as a result, the decommissioning trust funds were removed from our Consolidated Balance Sheets. CENG is obligated to decommission its nuclear power plants after these plants cease operation. The 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. The decommissioning trust fund strategy is based on estimates of the costs to perform the decommissioning and the timing of incurring those costs. When developing estimates of future fund earnings, CENG considered the asset allocation investment strategy, rates of return earned historically, and current market conditions.

        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, additional funding would have to be provided.

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.

Coal

We purchase the majority of our coal for electric generation under supply contracts with mine 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:

(1)

Assuming 100% sub-bituminous coal

        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 and terminal 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 switching to sub-bituminous coal from either the Western United States or Indonesia at C.P. Crane and have the ability to switch to using imported coal at Brandon Shores and H.A. Wagner 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 (NO_x), and mercury emissions. To comply with the HAA requirements, we are planning to burn domestic and/or import compliance coals (1.2 lb/mmbtu SO₂ or less) at H.A. Wagner. The C.P. Crane station is being converted to burn up to 100% sub-bituminous coal. Conversion is expected to be completed by May 2010. We are installing flue gas desulfurization (FGD) equipment on both Brandon Shores units. Installation is expected to be completed in March 2010. With the FGD installation, Brandon Shores will be able to burn higher sulfur coals (limit 6 lbs/mmbtu or approximately 3.5% sulfur) while simultaneously reducing station emissions. We plan to test burn some higher sulfur coals at Brandon Shores in 2010. The blend of coals actually procured for Brandon Shores will be optimized to achieve the lowest delivered cost while complying with HAA limitations.

        We own an undivided interest in the Keystone and Conemaugh electric generating plants in Western Pennsylvania. Our ownership interests in these plants are 20.99% in Keystone and 10.56% in Conemaugh.

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All of the Conemaugh and Keystone plants' annual coal requirements are purchased from regional suppliers on the open market. FGD equipment was installed on both of the Keystone units in 2009 and has been installed on both Conemaugh units since the mid-1990s. The FGD SO₂ restrictions on coal are 6 lbs/mmbtu (or approximately 3.7% sulfur) for the Keystone plant and approximately 4.9 lbs/mmbtu (or 3% sulfur) for the Conemaugh plant. The blend of coal procured is optimized to ensure compliance with station emission limits at the lowest delivered cost.

        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 2007 through 2009, 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.

        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, restructured states often consider new market rules and re-regulation measures that could result in more limited opportunities for competitive energy suppliers like Constellation Energy. The activity around re-regulation, however, has slowed due to the current environment of declining power prices. While there is activity in this area, we believe there is adequate growth potential in the current deregulated market.

        The market for commercial, industrial, and governmental energy supply continues to grow and we continue to experience increased competition from energy and non-energy market participants on a regional and national basis in our retail customer supply activities. Strong retail competition and the impact of wholesale power prices compared to the rates charged by local utilities affects the contract margin we receive from our customers. The recent credit crisis has increased overall margins reflecting an appropriate return on capital to support the business. Our experience and expertise in assessing and managing risk and our strong focus on customer service should help us to remain competitive during volatile or otherwise adverse market circumstances.

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Merchant Energy Operating Statistics

Operating statistics do not reflect the elimination of intercompany transactions.

*

2009 reflects our 100% ownership in our nuclear business through November 6, 2009 and our 50.01% ownership in our nuclear business from November 6, 2009 through December 31, 2009 following the sale of a 49.99% membership interest in CENG.

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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 by the Maryland PSC 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 by the Maryland PSC to provide several variations of SOS to commercial and industrial customers depending on customer load.

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.

        Pursuant to the order issued by the Maryland PSC in October 2009 approving our transaction with EDF, Constellation Energy agreed to fund a one-time per customer distribution rate credit for BGE residential customers, before the end of March 2010, totaling

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$110.5 million, or approximately $100 per customer, for which we recorded a liability in November 2009. In December 2009, BGE filed a tariff with the Maryland PSC stating we would give residential customers a rate credit of exactly $100 per customer. As a result, we accrued an additional $1.9 million for a total fourth quarter 2009 accrual of $112.4 million. Constellation made a $66 million equity contribution to BGE in December 2009 to fund the after-tax amount of the rate credit as required by the Maryland PSC order.

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.

        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.

        In July 2009, BGE filed with the Maryland PSC a proposal for a comprehensive smart grid initiative. The proposal includes the planned installation of 2 million residential and commercial electric and gas smart meters. We expect the total cost of the program to be approximately $480 million. In October 2009, the United States Department of Energy selected BGE as a recipient of $200 million in federal funding for our smart grid initiative. This grant allows BGE to be reimbursed for smart grid expenditures up to $200 million, substantially reducing the total cost of this initiative. However, the United States Department of Energy may withhold funding until approval is obtained from the Maryland PSC. The Maryland PSC held hearings on this proposed program in late 2009 and early 2010 and expects to issue a ruling in the second quarter of 2010. If BGE's proposal is approved by the Maryland PSC, BGE plans to proceed with this program as soon as practical.

        In the summer of 2009, BGE conducted a second season of a pilot program to evaluate pricing options designed to encourage customers to decrease energy use during peak demand periods. Additionally, BGE originally 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 approved a full portfolio of conservation programs for implementation in 2009 as well as a customer surcharge to recover the associated costs.

Transmission and Distribution Facilities

BGE maintains approximately 240 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.

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BGE Electric Operating Statistics

(1)

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. Additionally, in 2009, the Maryland PSC required BGE to obtain some of its summer gas purchases for injection into storage at fixed prices. BGE purchased approximately 5.9 million dekatherms (DTH) of gas for summer storage injections under fixed price contracts with a weighted average price of $4.61 per DTH. 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 DTH per day.

        BGE's current maximum storage entitlements are 297,091 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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BGE Gas Operating Statistics

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

New 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. In 2008, we contributed additional assets which had a book value of $2.0 million.

        In 2009, we and EDF have each contributed an additional $91.6 million to UNE to fund its capital requirements.

        Beginning on January 1, 2010, UNE's results of operations and financial condition will become part of our Generation reportable segment.

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,

•

energy performance contracting and energy efficiency engineering services,

•

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.

        Beginning on January 1, 2010, our Energy Projects and Services operation's results of operations and financial condition will become part of our Customer Supply reportable segment.

Home Products and 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 electricity and natural gas to residential customers.

        Beginning on January 1, 2010, our Home Products and Gas Retail Marketing operation's results of operations and financial condition will become part of our Customer Supply reportable segment.

Consolidated Capital Requirements

Our total capital requirements for 2009 were $1.6 billion. Of this amount, $1.2 billion was used in our nonregulated businesses and $0.4 billion was used in our regulated business. We estimate our total capital requirements will be $1.1 billion in 2010.

        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 $1.1 billion during the five-year period 2005-2009 to comply with existing environmental standards and regulations, including the Maryland HAA. Our estimated environmental capital requirements for the next three years are approximately $60 million in 2010, $25 million in 2011, and $35 million in 2012.

Air Quality

Federal

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

National Ambient Air Quality Standards (NAAQS)

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

        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 NO_x 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 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 NO_x

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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.

        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 Clean Air Mercury Rule (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 announced that it intends to develop new hazardous air pollutant emission standards under the CAA by the end of 2011. Any new standards that require the installation of additional emissions control technology beyond what is required under Maryland's HAA and CPR, 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, C.P. Crane, and H. A. 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, NO_x, 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 SO_2, NO_x, 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, but 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, NO_x, and mercury emissions reductions than those required under CAIR and CAMR.

        Maryland also is in the process of changing its current opacity regulations consistent with its commitment to resolve long-standing industry concerns about the regulations' continuous compliance requirements. In the interim, emergency opacity regulations have been implemented that will enable our plants to remain in compliance. We anticipate that the permanent regulations that Maryland is in the process of adopting will be consistent with the emergency regulations.

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

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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 $20 million in 2010, $20 million in 2011, $20 million in 2012 and $20 million from 2013-2014.

        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

In response to the anticipated challenges of global climate change, we believe it is imperative to slow, stop and reverse the growth in greenhouse gas emissions. Climate change could pose physical risks, such as more frequent or more extreme weather events, that could affect our systems and operations; however, uncertainty remains as to the timing and extent of any direct, climate-related impacts to our systems and operations. Extreme weather can affect the supply of and demand for electricity, natural gas and fuels and these changes may impact the price of energy commodities in both the spot market and the forward market, which may affect our financial results. In addition, extreme weather typically increases demand for electricity and gas from BGE's customers.

        There is increasing likelihood that greenhouse gas emissions regulation will occur at the international or federal level and/or continue to occur at the state level although considerable uncertainty remains as to the nature and timing of such regulation. Climate-related legislation is currently pending in the United States Congress. In September 2009, the Environmental Protection Agency issued an "endangerment and cause or contribute finding" for greenhouse gases under the Clean Air Act and proposed regulations to address greenhouse gas emissions. The proposed regulations would require large facilities that emit at least 25,000 tons of greenhouse gases a year, which would include many of our fossil fuel generating facilities, to obtain construction and operating permits covering these emissions. The proposed regulations could also eventually require installation of best available control technology for emissions control or reduction, although it is not possible to determine at this time the nature or extent of such controls.

        Additionally, 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 carbon dioxide (CO₂) allowances associated with Maryland's power plants, which include plants owned by us. Auctions have occurred quarterly since September 2008. Although we did not incur material costs in these auctions, we could incur material costs in the future to purchase allowances necessary to offset CO₂ emissions from our plants. Although we participate in RGGI, we believe a patchwork of climate policy and regulatory approaches across different states, regions or industry sectors has the potential to inequitably raise costs to particular businesses and/or drive the reallocation of emissions without actually achieving the desired overall reduction of emissions. In addition to Maryland, 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 monitor international developments and proposed federal and state legislation and regulations and evaluate the potential impact on our operations. In the event that additional 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, and our compliance costs could be material.

        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 has an overall CO₂ emission rate that is lower than the industry average with a substantial amount of the fleet's output coming from nuclear and hydroelectric plants, which generate significantly lower CO₂ emissions than fossil fuel plants. We are also at the forefront of the proposed development of new nuclear generation in the United States, which, if successful, would further lower our generation fleet's overall CO₂ emission rate. We also have experience trading in the markets for emissions allowances and renewable energy credits and our Customer Supply operation has expertise in providing

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renewable energy products and services to retail customers.

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 ruled in April 2009 that the EPA has a right to consider cost-benefit analysis in such decisions.

        The EPA is expected to propose new regulations in mid-2010. We will evaluate our compliance options in light of the Supreme Court and Second Circuit decisions, the EPA's July 2007 order, relevant state regulations and interpretations, 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 2009, following the Tennessee Valley Authority ash release, the EPA announced it is considering regulating ash as a hazardous waste. Depending on its final scope, additional federal regulation has the potential to result in additional compliance requirements and costs that could be material. In addition, the Maryland Department of the Environment finalized regulations governing the disposal, storage, use and placement of ash in December 2008.

        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

Constellation Energy and its consolidated subsidiaries (excluding CENG, which was deconsolidated on November 6, 2009) had approximately 7,200 employees at December 31, 2009.

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 may continue to 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 and banking markets, as well as the periodic use of commercial paper 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.

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 involve 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. We intend to use a portion of the proceeds received from the sale of an interest in our nuclear business to acquire new plants in regions where we have significant customer supply operations. Acquired plants may not generate the projected rates of return or sufficiently match generation capacity with customer supply volumes causing an increase in collateral requirements. 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. We may also 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. Furthermore, increased energy conservation and use of renewable energy may reduce the value of our nonrenewable generation plants, as well as accelerate the obsolescence of older plants. If we cannot execute our generation investment plans successfully, our business, results of operations and financial condition could be adversely affected.

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Changes in the prices of commodities, initial margin requirements, collateral posting asymmetries and types of collateral impact our liquidity requirements.

Our business is exposed to market fluctuations in the price and transportation costs of electricity, natural gas, coal, 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, including:

•

In our Customer Supply operation, we generally do not receive collateral under contractual obligations to supply our customers, but our Global Commodities operation may hedge these transactions through purchases that generally require us to post collateral.

•

In our Generation operation, we may have to post collateral on our power sale or fuel purchase contracts.

        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 cash 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. Additionally, posting letters of credit to counterparties to meet collateral requirements adversely impacts our liquidity, while the receipt of letters of credit as collateral does not improve our liquidity.

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 our 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. In addition, new sources of natural gas supplies from domestic shale production, as well as rising liquid natural gas (LNG) exports, could increase the long-term supply of natural gas and create a fundamental and long-lasting decline in natural gas prices. Lower natural gas prices could contribute to a decline in power generation prices that could have an adverse effect on our financial results and cash flows. 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

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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.

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, 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.

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 economic value at risk, daily value at risk, and stress testing are based on historical price movements. If price movements significantly or persistently deviate from historical behavior, risk limits may not fully 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 and nonderivative 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, as well as nonderivative contracts, 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 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 derivative instruments could reflect a realized value that differs from our reported estimates of fair value.

Inaccurate assumptions and estimates in the models we use could adversely impact our financial results.

We deploy many models to value merchant contracts, derivatives and assets, to dispatch power from our generation plants, and to measure the risks and costs of various transactions and businesses. Also, a significant portion of our business relies on the assumptions underlying the forecasting of customer load, correlations between prices of energy commodities and weather and the creditworthiness of our customers and other third parties. Inaccurate estimates of various business assumptions used in those models could create the mispricing of customer contracts and assets or the incorrect measurement of key risks relating to our portfolios and businesses that could adversely impact our financial results.

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Poor market performance will affect our pension plan investments, which may adversely affect our liquidity and financial results.

At December 31, 2009, our qualified pension obligations were approximately $327 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.

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

We own, operate and have ownership interests in 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 our ownership interest in nuclear generating facilities.

We own substantial interests in nuclear power plants. 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 operation of nuclear generating facilities involves 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 the 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 nuclear joint ventures or another participating insured party's nuclear plants, CENG 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.

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.

        Examples of potential future regulatory changes include additional regulation of greenhouse gas emissions at the federal, regional, and/or state level, heightened enforcement of new source review requirements, increased regulation of coal combustion

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by-products, and mandated investment in renewable energy resources. One or more of these changes could increase our compliance and operating costs or require significant commitments of capital.

        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.

        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 or as a result of Maryland PSC policies or rulings, 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 is 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.

        We are subject to mandatory reliability standards enacted by the North American Electric Reliability Corporation (NERC) and enforced by the FERC. Compliance with the mandatory reliability standards may subject us to higher operating costs and may result in increased capital expenditures. If we are found to be in noncompliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties.

        Further, federal and/or state regulatory approval may be necessary for us to complete transactions. As part of the regulatory approval process, governmental entities may impose terms and conditions on the transaction or our business that are unfavorable or add significant additional costs to our future operations.

        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 in the State of Maryland, 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.

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Further, additional regulation of the derivatives markets has been proposed recently in the United States Congress and by the Commodity Futures Trading Commission, which could require us to post additional cash collateral and have a material adverse effect on our business. 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 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.

BGE's electric and gas infrastructure is subject to operational failure and may require significant expenditures to maintain.

Much of BGE's electric and gas operational systems and infrastructure, such as gas mains and pipelines and electric transmission and distribution equipment, has been in service for many years. Older equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including due to events that are beyond BGE's control, and may require significant expenditures to operate efficiently, which could have an adverse effect on our, or BGE's, 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 reduced revenues and 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. The process of estimating the load requirements of our customers has been further complicated by the decreased demand resulting from economic and financial instability since 2008. 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 reduce our revenues and/or 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

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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. Furthermore, terrorist attacks could compromise the physical or cyber security of our facilities, which could adversely affect our ability to manage these facilities effectively.

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

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. 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.

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.

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 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. In addition, exercise of the option may adversely impact our relationship with EDF, which could have an adverse impact on our CENG and UNE nuclear joint ventures with EDF. This put arrangement expires on December 31, 2010.

Our ability to develop new nuclear generation could have an effect on our business and financial results.

We are in the forefront of the proposed development of new nuclear generation in the United States through our UNE joint venture. Nuclear generation development projects are large and complex and there have been no new orders for a nuclear plant in the United States since the 1970s. The costs incurred to

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construct a new nuclear plant would be significant and adequate returns on investment may not be realized for many years, if at all. Feasibility and successful construction of nuclear plants depend on a variety of factors, including receipt of required permits, terms of financing, impact of competing generation and nuclear technologies, materials, labor and nuclear waste disposal costs and regulation of nuclear facilities. These factors could generate higher construction and financial costs, delays, environmental and other liabilities, or an adverse impact to our credit rating. These factors may also lead to a decision not to proceed with the construction of new nuclear facilities, which could have an adverse effect on our business and financial results, including a potential impairment of our investment in UNE.

Item 2. Properties

Constellation Energy occupies approximately 1,130,000 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 4,700 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.

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        The following table describes our generating facilities:

        In 2009, we signed an agreement to acquire the 70 MW Criterion wind project in Garrett County, Maryland. Upon closing, we plan to complete the construction of the project and expect it to be ready for commercial operation in late 2010.

        In December 2009, we were selected by the State of Maryland to develop an approximately 17 MW solar photovoltaic power installation in Emmitsburg, Maryland. This $60 million solar facility will be constructed, owned, operated and maintained by us. We expect the project to be completed by December 2012.

        In February 2008, we acquired the Hillabee Energy Center, a partially completed 740 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 the first quarter of 2010.

        As of December 31, 2009, we also have a 50% ownership interest in a waste coal processing facility located in Hazelton, Pennsylvania.

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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

        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 officer and any other person pursuant to which the officer was selected.

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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 29, 2010, there were 35,016 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, except certain of our credit facilities prohibit us from increasing our common stock dividend without the consent of the lenders.

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

        In January 2010, we announced a quarterly dividend of $0.24 per share payable April 1, 2010 to holders of record at the close of business on March 10, 2010. This is equivalent to an annual rate of $0.96 per share.

        Quarterly dividends were declared on our common stock during 2009 and 2008 in the amounts set forth below.

        BGE pays dividends on its common stock after its Board of Directors declares them. However, pursuant to the order issued by the Maryland PSC on October 30, 2009 in connection with its approval of the transaction with EDF, BGE cannot pay common dividends to Constellation Energy if (a) after the dividend payment, BGE's equity ratio would be below 48% as calculated under the Maryland PSC's ratemaking precedents or (b) BGE's senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. There are no other 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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

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

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Item 6. Selected Financial Data

Constellation Energy Group, Inc. and Subsidiaries

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

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

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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 and joint ventures 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 2009, 2008, and 2007. 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, 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

As a result of significant market events in 2008, we previously disclosed plans to refocus and, in some cases, exit parts of our merchant energy business. We also sought to increase available liquidity and reduce our business risk. In addition, in November 2009, we completed a transaction to sell to EDF Group and affiliates (EDF) a 49.99% interest in our nuclear generation and operation business. This transaction brought us stability as a stand-alone company as well as improved our liquidity. We discuss the transaction with EDF and our divestitures in Note 2 to Consolidated Financial Statements and our available liquidity and risk management activities later in this Item 7.

        We are pursuing a strategy of owning and operating 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 is focusing on short-term and long-term purchases and sales of energy, capacity, and related products to various customers, including distribution utilities, municipalities, cooperatives, and residential, 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 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.

        Our merchant energy business actively manages our Customer Supply operations with both physical and contractual assets in order to derive incremental value. The combination of our Generation and Customer Supply operations allows us to manage our Customer Supply operations in a collateral-efficient manner. Through our retail sales channels, we are able to manage our generation with lower requirements to post collateral. Additionally, when we use owned or contracted generation, we reduce our collateral posting requirements.

        We have load obligations greater than our generation assets. Going forward, we intend to buy generation assets and enter into longer-tenor agreements with merchant generators in regions where we currently serve load but do not have a significant generation presence. We believe that by better matching generating assets with our load obligations, we will be able to further reduce our dependence on exchange-traded products, thereby lowering our collateral requirements. We believe that the proceeds received from the transaction with EDF, along with overall market conditions, provide the resources and potential opportunities to add to our generation assets at attractive prices over the next two to three years.

        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

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strong balance sheet and investment-grade credit quality through the use of a business model that applies cash flow to reduce debt.

        While we pursue the above strategy with Generation and Customer Supply activities, we are continuing a disciplined approach to the management of our collateral requirements and liquidity, including:

•

pricing new business to reflect the full cost of capital in the current economic environment,

•

balancing operating cash flows with earnings growth,

•

maintaining a liquidity cushion in excess of credit-rating downgrade collateral requirements and market stress conditions,

•

using proceeds from the sale of a 49.99% membership interest in CENG to EDF to reduce our debt and maintain credit metrics consistent with investment grade ratings to support our Customer Supply operations, and

•

focusing on Constellation Energy's core strengths of:

•

owning, developing, and operating 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.

        We are also in the forefront of the proposed development of new nuclear generation in the United States through our UniStar Nuclear Energy (UNE) joint venture with EDF. EDF brings operational experience, global scale, and procurement leverage to the development of new nuclear plants in the United States.

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.

        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. In 2009, markets in which we operate were affected by declining prices for power, gas, and capacity.

        During 2009, we improved our liquidity and reduced our business risk in response to these market events. 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 impacts our business.

        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), and certain taxes and surcharges. The rates for BGE's regulated gas business continue to consist of a delivery charge (base rates as well as certain taxes and surcharges) and a commodity charge.

Order Approving Transaction with EDF

In October 2009, the Maryland PSC issued an order approving our transaction with EDF subject to the following conditions, with which both Constellation Energy and EDF are complying:

•

Constellation Energy is to fund a one-time per customer distribution rate credit for BGE residential customers, before the end of March 2010, totaling $110.5 million, or approximately $100 per customer, for which we recorded a liability and corresponding reduction in regulated electric and gas revenues in November 2009. In December 2009, BGE filed a tariff with the Maryland PSC stating we would give residential customers a rate credit of exactly $100 per customer. As a result, we accrued an additional $1.9 million for a total fourth quarter 2009 accrual of $112.4 million. Constellation Energy made a $66 million equity contribution to BGE in December 2009 to fund the after-tax amount of the rate credit as ordered by the Maryland PSC.

•

Constellation Energy is required to make a $250 million cash capital contribution to BGE by no later than June 30, 2010. Constellation Energy made this equity contribution to BGE in December 2009.

•

BGE will not pay common dividends to Constellation Energy if:

•

after the dividend payment, BGE's equity ratio would be below 48% as calculated pursuant to the Maryland PSC's ratemaking precedents, or

•

BGE's senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade.

•

BGE may file an electric and/or gas distribution rate case at any time beginning in January 2010 and may not file a subsequent electric and/or gas distribution rate case until January 2011. Any rate increase in the first electric distribution rate case will be capped at 5% as

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agreed to by Constellation Energy in its 2008 settlement with the State of Maryland and the Maryland PSC. BGE plans to file an electric and gas distribution rate case in the second quarter of 2010.

•

Constellation Energy will be limited to allocating no more than 31% of its holding company costs to BGE until the Maryland PSC reviews such cost allocations in the context of BGE's next rate case.

•

Constellation Energy and BGE are required to implement "ring fencing" measures designed to provide bankruptcy protection and credit rating separation of BGE from Constellation Energy. Such measures include the formation of a new special purpose subsidiary by Constellation Energy to hold all of the common equity interests in BGE. We completed the implementation of these measures in February 2010.

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 closed 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 Calvert Cliffs Unit 1 and Unit 2, scheduled to begin 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 increase in electric distribution revenue awarded in the first electric distribution rate case filed by BGE after the settlement will be capped at 5% with certain exceptions. 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 and $25.2 million in 2009 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.

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

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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 did not recommend returning the former utility generation assets to full cost of service regulation, but rather recommended incremental, forward looking re-regulation when appropriate to ensure a reliable supply of electricity or to obtain economic benefits for customers. In 2009, the Maryland PSC continued to examine how to procure electric supply for Maryland residents, from modifications to the existing auction process to requiring that new generation be built by the utilities or by third parties. 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, subject to limitations in the Maryland PSC's October 2009 order approving our transaction with EDF. 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).

Revenue Decoupling

The Maryland PSC has allowed us to record a monthly adjustment to our electric distribution revenues from residential and small commercial customers since 2008 and for the majority of our large commercial and industrial customers since February 2009 to eliminate the effect of abnormal weather and usage patterns per customer on our electric distribution volumes, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in consumption levels. This means BGE recognizes revenues at Maryland PSC-approved levels per customer, regardless of what actual distribution volumes were for a billing period. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions. We then bill or credit impacted customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings. 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.

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 a number of orders covering various new transmission investment projects since 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.

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        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 Global Commodities operation. FERC has stated that it would issue a substantive order on the ALJ's decision no later than the end of May 2010. Nonetheless, the amounts collected under the SECA rates are subject to refund and the ultimate outcome of the proceeding establishing SECA rates is uncertain. Depending on the ultimate outcome, the proceeding may have a material effect on our financial results.

Capacity Markets

In general, capacity market design revisions are routinely proposed and considered on an ongoing basis. Such changes are subject to FERC's review and approval. Currently, we cannot predict the outcome of these proceedings or the possible effect on our, or BGE's, financial results.

        Through 2008 and 2009, PJM made several filings at FERC proposing various revisions to its capacity market, or Reliability Pricing Model (RPM), including the determination of the cost-of-new-entry (CONE), which is an important component in determining the price paid to capacity resources in PJM. PJM also proposed revisions relating to the participation of energy efficiency and demand resources, and market power and mitigation rules. Some of these matters are still pending at FERC. While recent RPM design changes have not yet had a material effect on our financial results, we cannot predict the outcome of the issues still pending or on any capacity market design changes that result from new regulatory requirements. Such changes could have a material impact on our financial results.

        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. In September 2008, FERC dismissed the complaint and in October 2008, the complainants requested a rehearing at FERC. FERC denied rehearing and ultimately the case was appealed and is pending before the United States Court of Appeals for the District of Columbia. 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.

        In April 2009, the Attorney General of Connecticut, the Connecticut Department of Public Utilities and Office of Consumer Counsel (together, the Connecticut Parties) filed complaints at FERC alleging improper energy bidding behavior since December 1, 2006 by generators located in New York that also received capacity payments within ISO-New England. In May 2009, the Connecticut Parties filed an amended complaint asserting that Constellation Energy Commodities Group, Inc. (CCG) and others received capacity payments while never intending to perform as capacity resources. The revised allegations assert that certain generators engaged in "economic withholding" by submitting energy bids at or near the offer cap. Since December 2006, CCG has received approximately $7 million in payments for capacity offered into ISO-New England associated with Constellation Energy's nuclear facilities located in NY. In August 2009, FERC issued an order setting this matter for a public hearing before an ALJ to determine the intent of the capacity suppliers (including CCG) in making their energy offers in ISO-New England. CCG is participating in the administrative hearing, which is ongoing and has maintained its

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adherence to all applicable rules and regulations relating to the market activity. However, we cannot predict the outcome of the FERC hearing or any potential liability that CCG may incur.

        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, both in the states and 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.

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 and cyber-security 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.

        Given the increasing concern over the security of the country's energy infrastructure, there could be future rules or regulations related to the operation and security requirements of our generating facilities and electric and gas transmission and distribution systems, which could have a material impact on our operations and financial results.

Commodity Futures Trading Commission

The United States Congress and the Commodity Futures Trading Commission (CFTC) are evaluating additional laws and regulations for the derivatives markets, including position limits and eliminating regulatory exemptions for hedging activity. We are unable to determine the final form any regulations or new laws may take, but such laws or regulations could have a material effect on our business.

Market Oversight

Regulatory agencies that have jurisdiction over our businesses, including the FERC and CFTC, possess broad enforcement and investigative authority to ensure well functioning markets and to prohibit market manipulation or violations of the agencies' rules or orders. These agencies also possess significant civil penalty authority, including in the case of FERC and the CFTC, the authority to impose a penalty of up to $1 million per day per violation. We are committed to a culture of compliance and ensuring compliance with all applicable rules, laws and orders. Nonetheless, the regulatory agencies engage in either public or non-public investigations in response to allegations of wrongdoing and we may be involved in certain market activities that become subject to investigations. Even where no wrongdoing is found, the process of participating in a regulatory investigation could have a material effect on our business.

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,

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•

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 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. Because of the extensive nature of the accounting requirements that govern both accounting treatment and documentation, as well as the complexity of the transactions within its scope, management is required 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 the derivative accounting requirements, failure to meet these requirements, even inadvertently, could require the use of a different accounting treatment for the affected transactions. In addition, interpretations of these accounting requirements continue to evolve, and future changes 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 and applying that definition to each individual contract. If a contract is not a derivative, we cannot apply derivative accounting, 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 derivative accounting, 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

We are permitted several possible accounting treatments for derivatives that meet all of the applicable requirements. Mark-to-market is 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

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must meet specific, restrictive criteria, both at the time of designation and on an ongoing basis.

        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:

        We exercise judgment in determining which derivatives qualify for a particular accounting treatment, 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, we are not required to designate and account for all such contracts 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 for derivatives 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 (AOCI). Additionally, the selection of accounting treatment also affects the amount and timing of the recognition of earnings. The following table summarizes these impacts:

Valuation

We 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

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affected by many factors including, but not limited to, the following:

•

uncertainty surrounding inputs to the estimates of fair value 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,

•

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. 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 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. 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, CENG, UNE, CEP and partnerships that own power projects) to determine whether or not they are impaired. The standard for determining whether an impairment must be recorded is whether the investment has experienced an "other than a temporary" decline in value.

        The evaluation and measurement of investment impairments involves the same uncertainties as described above for long-lived assets that we own directly. 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, we would record our proportionate share of that impairment loss and would evaluate our investment for an other than temporary decline in value.

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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 nuclear joint ventures and CEP. These issues include environmental and legislative initiatives as well as events that will impact the viability of new nuclear development. 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.

        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, and any losses recognized could be material.

Debt and Equity Securities

Our available for sale investments in debt and equity securities are subject to impairment evaluations. Our most significant available for sale securities were the nuclear decommissioning trust fund assets. However, upon the completion of our transaction with EDF on November 6, 2009, we no longer reflect the nuclear decommissioning trust fund assets on our Consolidated Balance Sheets. To the extent that CENG impairs its nuclear decommissioning trust fund assets, we will report our share of the impairment as part of our equity investment earnings in CENG.

        We 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 through November 6, 2009 for which the market value was below book value, the decline in fair value for these securities was considered other than temporary, and the securities were 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 do not amortize goodwill. We 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.

Significant Events

Sale of 49.99% Membership Interest in CENG to EDF

On November 6, 2009, we sold a 49.99% membership interest in CENG, our nuclear generation and operation business. The following summarizes where we disclose the significant impacts of this transaction on us:

•

We provide an overview of this transaction in Item 1. Business section.

•

Upon the close of this transaction, we deconsolidated CENG and recorded our initial investment in CENG on our Consolidated Balance Sheets. We discuss the significant changes as a result of recording the transaction and the deconsolidation of CENG on our Consolidated Balance Sheets and the expected impact on our ongoing financial results and cash flows in this section.

•

As a result of recording the transaction, we have presented certain additional line items on our consolidated financial statements in Item 8, such as our investment in CENG, the gain on sale, and the proceeds received from the transaction.

•

We recorded a significant gain on the sale of the 49.99% membership interest as well as on our retained interest at transaction close. The fair value of our investment in CENG exceeded our share of CENG's equity because CENG's assets and liabilities retained their historical carrying value. This basis difference will be amortized as a reduction to our future equity in earnings of CENG. We discuss this item in Notes 2 and 4 to Consolidated Financial Statements.

•

We discuss the Maryland PSC order approving the transaction in Note 2 to Consolidated Financial Statements.

•

The closing of the transaction impacted our credit facilities and, therefore, our net available liquidity. We discuss our net available liquidity in this section.

•

A portion of the proceeds received from the transaction will be used to retire approximately $1 billion of debt prior to its maturity. We discuss our debt retirements to date in Note 9 to Consolidated Financial Statements.

•

Given the significance of our investment in CENG, we are exposed to many of the same risks as CENG. CENG is exposed to risks associated with operating nuclear generating facilities and the risk of a nuclear accident. We discuss our exposure to certain of these risks in Note 12 to Consolidated Financial Statements.

•

We entered into the following agreements with CENG:

•

a power purchase agreement,

•

a power services agency agreement, and

•

an administrative services agreement.

We discuss the nature and purpose of these agreements in Note 16 to Consolidated Financial Statements.

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BGE Residential Customer Rate Credit

On October 30, 2009, as part of the order approving our transaction with EDF, the Maryland PSC required Constellation Energy to fund a one-time distribution rate credit to be given to BGE residential customers before the end of March 2010 totaling $110.5 million, or approximately $100 per customer. In December 2009, BGE filed a tariff with the Maryland PSC stating BGE would give residential customers a distribution rate credit of exactly $100 per customer. We recorded the total credit of $112.4 million in the fourth quarter of 2009 and will apply it to customer bills in the first quarter of 2010 as required under the order. Constellation Energy made a $66 million equity contribution to BGE in December 2009 to fund the after-tax amount of the rate credit as required by the Maryland PSC order approving the transaction with EDF. We discuss BGE's residential customer rate credit in Note 2 to Consolidated Financial Statements.

Contribution to BGE

On October 30, 2009, as part of the order approving our transaction with EDF, the Maryland PSC required Constellation Energy to provide a $250 million cash capital contribution to BGE by no later than June 30, 2010. Constellation Energy made this contribution in December 2009.

Acquisitions

In July 2009, we acquired CLT Efficient Technologies Group (CLT), an energy services company.

        On November 30, 2009, we signed an agreement to acquire the Criterion wind project in Garrett County, Maryland.

        We discuss these acquisitions in more detail in Note 15 to Consolidated Financial Statements.

Divestitures

During 2009, we completed the following divestitures:

(1)

Simultaneously with this divestiture, we entered into an agreement with the buyer to provide us with the gas supply needed to support our retail gas customer supply operations.

        We discuss these divestitures and the gas supply agreement in more detail in the Note 2 to Consolidated Financial Statements.

Merger Termination and Strategic Alternatives Costs

Throughout 2009, we incurred merger termination and strategic alternatives costs related to the terminated merger with MidAmerican Energy Holdings Company (MidAmerican) in 2008, the conversion of our Series A Preferred Stock into a note, the transactions related to EDF, and other strategic alternatives costs. We discuss costs related to the mergers and strategic alternatives in more detail in Note 2 to Consolidated Financial Statements.

Impairment Losses and Other Costs

Throughout 2009, we recorded impairment losses and other costs on certain of our equity method investments, investments in equity securities and other assets. We discuss these charges in more detail in the Note 2 to Consolidated Financial Statements.

Workforce Reduction Costs

During 2009, we incurred workforce reduction costs primarily related to the divestiture of a majority of our international commodities operation as well as other smaller restructurings elsewhere in our organization. We recognized a $12.6 million pre-tax charge in 2009 related to the elimination of approximately 180 positions. We expect all of these restructurings will be completed within 12 months from the program's initiation. We discuss our workforce reduction costs in more detail in Note 2 to Consolidated Financial Statements.

Redemption of Notes

In the fourth quarter of 2009, we redeemed our Zero Coupon Senior Notes early and recognized a pre-tax loss of $16.0 million.

        In February 2010, we retired certain of our 7.00% Notes due April 1, 2012 as part of a cash tender offer launched in January 2010 and issued call notices to retire certain tax exempt notes.

        We discuss these transactions in more detail in Note 9 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 (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 Item 1 Business—Overview section and in the Strategy and Significant Events sections, Constellation Energy's 2009 and 2008 operating results were materially impacted by a number of significant events, transactions, and changes in our strategic direction. The impact of these items has affected the comparability of our 2009 and 2008 results to prior periods and will alter Constellation Energy's operating results in the future. In this section, we highlight the 2009 and 2008 impacts of these items.

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Overview

Results

        Our total net income attributable to common stock for 2009 improved compared to 2008 by $5.8 billion, or $29.53 per share, mostly because of the following:

        Our total net loss attributable to common stock for 2008 deteriorated compared to 2007 by $2.1 billion, or $11.84 per share, mostly because of the following:

Other Items Included in Operations (after-tax):

(1)

These amounts include the net losses on the sales of the international commodities operation, gas trading operation, certain other trading operations, and a uranium market participant, the reclassification of losses on previously designated cash-flow hedges from Accumulated Other Comprehensive Loss because the forecasted transactions are probable of not occurring, and earnings that are no longer part of our core business. The impairment losses and other costs and workforce reduction costs line items also include amounts related to the operations we divested.

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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 limited risk capital.

        At the beginning of 2009, we outlined various strategic initiatives to reduce risk for our Global Commodities operation. As of December 31, 2009, these initiatives have been completed. We discuss our current strategy in more detail in the Strategy section.

        The execution of our strategy in the future may be affected by 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.

        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 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 limited risk capital in the management of our portfolio in order to earn returns. We discuss the impact of our trading activities and economic value at risk in more detail in the Mark-to-Market and Risk Management sections.

Results

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.

(1)

Amount includes the net losses on the sales of the international commodities operation, gas trading operation, certain other trading operations, and a uranium market participant, the reclassification of losses on previously designated cash-flow hedges from Accumulated Other Comprehensive Loss because the forecasted transactions are probable of not occurring, and earnings that are no longer part of our core business. The impairment losses and other costs and workforce reduction costs line items also include amounts related to the operations we divested.

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Effects of Transaction with EDF on Statement of Income (Loss)

Prior to November 6, 2009, CENG was a 100% owned subsidiary, and we consolidated its financial results within our Consolidated Statements of Income (Loss). On November 6, 2009, we completed the sale of a 49.99% membership interest in CENG to EDF, and we deconsolidated CENG. Accordingly, for the period from November 6, 2009 through December 31, 2009, we ceased recording CENG's financial results and began to record equity investment earnings from CENG as well as the effect of our PPA and other transactions with CENG. We discuss our transaction with EDF in more detail in Note 2 to Consolidated Financial Statements.

        For the period from January 1, 2009 through November 6, 2009, our merchant energy results included the following financial results of CENG:

        As a result of deconsolidation, we expect that our future merchant energy results will differ from historical results primarily due to the following factors:

•

Revenues—We will sell between 85-90% of the output of CENG's plants, excluding output sold by CENG directly to third parties, rather than 100% of the plants' total output including volumes contracted to third parties.

•

Fuel and purchased energy expenses—We will not include nuclear fuel expense but instead will reflect our purchase of between 85-90% of the output of CENG's plants, excluding output sold directly to third parties, as provided under the terms of the PPA with CENG.

•

Operating expenses—We will no longer include CENG's plant operating costs or general and administrative expenses.

•

Depreciation and amortization expense—We will no longer include deprecation of CENG's nuclear plants.

        Additionally, we will record our 50.01% share of CENG's financial results and amortization of the CENG basis difference in the "Equity Investment (Losses) Earnings" line in our Consolidated Statements of Income (Loss). We discuss the accounting for our retained investment in CENG in more detail in Note 2 to 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 operations 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 mark-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 $4,257.0 million in 2009 compared to 2008 and decreased $2,045.9 million in 2008 compared to 2007 primarily due to the following:

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Fuel and Purchased Energy Expenses

Our merchant energy fuel and purchased energy expenses decreased $4,318.3 million in 2009 compared to 2008 and decreased $1,710.4 million in 2008 compared to 2007 primarily due to the following:

Gross Margin

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

•

Generation—our operation that owns, operates, and maintains fossil, nuclear (through November 6, 2009), and renewable generating facilities and holds indirect interests in nuclear generating facilities (since November 6, 2009), qualifying facilities, and power projects in the United States. 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. Gross margin excludes our equity investment earnings from our nuclear joint ventures, qualifying facilities, and power projects. We discuss our treatment of equity investment earnings in more detail in Note 1 to Consolidated Financial Statements.

•

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 including decreased demand related to the current economic environment. 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 and natural gas properties, provides risk management 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:

Generation

The $57 million increase in Generation gross margin in 2009 compared to 2008 is primarily due to the following:

•

$178 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 2008 (see Global Commodities discussion below for impact of price changes during 2009), and

•

$130 million due to the timing and duration of planned and unplanned outages at our generating plants.

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        These increases were partially offset by the following:

•

$245 million of lower gross margin on our nuclear fleet as a result of the deconsolidation of CENG following the sale of a 49.99% membership interest to EDF on November 6, 2009, and

•

$6 million of lower gross margin primarily related to our investments in power projects.

        The $221 million increase in Generation gross margin in 2008 compared to 2007 is primarily due to the following:

•

$210 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.

        In 2010, our gross margin for Generation will be lower than in 2009 as a result of the sale of a 49.99% membership interest in CENG to EDF on November 6, 2009.

Customer Supply

The $34 million increase in Customer Supply gross margin in 2009 compared to 2008 is primarily due to the following:

•

$108 million of higher gross margin mostly related to the consolidation of a retail power supply variable interest entity for which we became the primary beneficiary in December 2008 and consolidated, and

•

$9 million of higher mark-to-market results primarily in our retail gas operation. We discuss these results in more detail in the Mark-to-Market section.

        These increases were partially offset by the following:

•

$66 million of lower gross margin as a result of fewer customers and unfavorable variable load risk associated with wholesale and retail power primarily due to variances from normal weather and lower demand resulting from the economic downturn and our efforts to reduce risk in the business, and

•

$17 million related to lower realization of contracts executed in prior periods and lower volumes in our wholesale and retail power supply operations, partially offset by higher margins on new business originated and realized during 2009.

        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,

•

$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.

Global Commodities

We analyze 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.

•

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). During 2009, we reduced our participation in the coal, freight and gas trading markets through the divestiture of our international coal and freight and our natural gas trading businesses.

•

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. We sold our interest in the entity that owns dry bulk cargo vessels during 2009.

        The $30 million decrease in gross margin from our Global Commodities operation during 2009 compared to the same period of 2008 is primarily due to:

•

$140 million of lower gross margin from our energy investments operation primarily related to lower business realized on our upstream gas activities within 2009, and

•

$139 million of lower gross margin in our structured products portfolio primarily as a result of fewer transactions during 2009.

        These decreases were partially offset by an increase of $249 million in our portfolio management and trading operation. These changes are discussed further in the table below.

        As previously discussed, the energy markets were affected by substantial volatility in commodity prices during 2008. These market impacts are reflected in the $433 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, which are discussed further in the table below. This is partially offset by:

•

$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

•

$57 million in our energy investments operation primarily due to higher realization of contracts executed in prior periods.

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        Our portfolio management and trading operation gross margin increased $249 million in 2009 compared to 2008 and decreased $698 million in 2008 compared to 2007 primarily due to the following:

Mark-to-Market

Mark-to-market results include net gains and losses from origination, risk management, and trading 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.

        The nature of our operations and the use of mark-to-market accounting for certain activities create fluctuations in mark-to-market earnings. 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.

        During 2009, we focused our activities on reducing capital requirements, reducing long-term economic risk, and reducing short- and interim-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, while in general the underlying physical transactions related to these activities 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.

        Mark-to-market results were as follows:

*

Total unrealized mark-to-market is the sum of origination transactions and total risk management and trading—mark-to-market.

**

Includes gains (losses) on hedge ineffectiveness for fair value hedges recorded in gross margin.

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        Total mark-to-market results decreased $445.9 million during the year ended December 31, 2009 compared to the same period of 2008. The period-to-period variance in unrealized changes in fair value was due to decreased unrealized risk management and trading results of $372.1 million and the decrease in origination gains of $73.8 million. We discuss the decrease in origination gains below.

        The decrease in risk management and trading results of $372.1 million was primarily due to:

•

$203 million of lower results in our domestic coal portfolio primarily as a result of less favorable price movements relating to economic hedges which substantially decreased in value as coal prices decreased in 2009,

•

$104 million of lower gains in our international coal and freight operation as a result of its divestiture in March 2009,

•

$123 million of lower gains in our wholesale natural gas risk management and trading operation primarily as a result of the divestiture of our natural gas trading operation in the beginning of April 2009, and

•

$45 million of lower results related to our emissions trading activities primarily as a result of a less favorable price environment.

        These decreases were partially offset by the following:

•

$84 million of higher results on open positions primarily due to the absence of losses in our power and transmission risk management activities primarily in the PJM, Northeast, and New York regions as a result of a more favorable price environment in 2009 and our activities to reduce risk and improve liquidity, and

•

$19 million of lower losses in our retail gas portfolio primarily due to a more favorable price environment in 2009.

        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 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.

        We did not record any origination gains during 2009. 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 became derivatives subject to mark-to-market accounting. The change in accounting for these contracts from nonderivative to derivative resulted in substantially all of the origination gains for 2008 presented in the unrealized mark-to-market results 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. 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, 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.

        The recognition of origination gains is generally dependent on sufficient available 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, 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.

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Derivative Assets and Liabilities

Derivative assets and liabilities consisted of the following:

        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 in Note 13 to Consolidated Financial Statements.

        The decrease of $1,246.6 million in our net derivative liability subject to hedge accounting since December 31, 2008 primarily was due to $1,896 million of realization of out-of-the-money cash-flow hedges at the time the forecasted transaction occurred, partially offset by $649 million of increased unrealized losses on our remaining out-of-the-money cash-flow hedge positions primarily related to decreases in power, natural gas, and coal prices during 2009.

        The following are the primary sources of the change in our net derivative asset subject to mark-to-market accounting during 2009 and 2008:

        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 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.

•

Contracts acquired represents the initial fair value of acquired derivative contracts recorded in "Derivative assets and liabilities" in our Consolidated Balance Sheets. Substantially all of this activity for 2009 related to the divestiture of our international commodities operation, Houston-based gas trading operation, and certain other trading operations in order to transfer risk and reward to the buyers.

•

Dedesignated contracts and other changes in fair value include transfers of derivative contracts from cash-flow hedges to mark-to-market treatment, transfers of derivative contracts from mark-to-market treatment to cash-flow hedges, and those derivative contracts that did not meet the qualifications of cash flow hedge accounting. During 2009, substantially all of the activity related to dedesignations in connection with the strategic objective of restructuring and reducing the risk of our portfolio.

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        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 are as follows as of December 31, 2009:

        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 $195.5 million during 2009 as compared to 2008 due to lower performance-based labor and benefit costs of $95.7 million and lower non-labor operating expenses of $99.8 million, part of which represents the absence of costs from the divestitures completed in 2009 and from deconsolidating CENG on November 6, 2009.

        Our merchant energy business operating expenses decreased $62.1 million during 2008 compared to 2007 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.

        For 2010, we expect a further decrease in operating expenses as a result of the deconsolidation of CENG on November 6, 2009. We discuss this impact further in the Effects of Transaction with EDF on Statement of Income (Loss) section.

Merger Termination and Strategic Alternatives Costs

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

Impairment Losses and Other Costs

Our impairment losses 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.

Amortization of Credit Facility Amendment Fees

Our merchant energy business incurred costs related to the amortization of credit facility amendment fees in connection with the EDF transaction. These costs are classified as part of "Other income (expense)" in our Consolidated Statements of Income (Loss).

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Depreciation, Depletion and Amortization Expense

Our merchant energy business incurred lower depreciation, depletion and amortization expenses of $36.9 million during 2009 compared to 2008 due to the absence of depletion expenses of $43.1 million as a result of divestitures made in 2008 in our upstream gas operations, partially offset by an increase of $6.2 million in depreciation on our generating facilities.

        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.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $15.8 million in 2009 compared to 2008, due to $8.1 million of lower gross receipts taxes at our retail customer supply operation, $5.8 million of lower production taxes related to our upstream gas producing properties, and $1.9 million in lower property, franchise, and other taxes.

        Taxes other than income taxes increased $14.1 million in 2008 compared to 2007, 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.

Gain on Sale of 49.99% Interest in CENG

On November 6, 2009, we completed the sale of a 49.99% membership interest in CENG to EDF. As a result of this sale, we recognized a $7.4 billion pre-tax gain. We discuss this transaction in Note 2 to Consolidated Financial Statements.

(Loss) Gain on Divestitures

During 2009, we sold a majority of our international commodities operation, our Houston-based gas trading operation, certain other trading operations, and a uranium market participant, and we recognized a pre-tax loss of $464.2 million.

        During 2008, we recognized net gains of $25.5 million, including a $14.3 million gain, net of the noncontrolling 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 these divestitures in more detail in Note 2 to Consolidated Financial Statements.

Equity Investment (Losses) Earnings

During 2009, our equity investment earnings decreased $63.6 million from 2008 primarily due to $39.1 million of lower earnings from our shipping joint venture as a result of the sale of our interests in July 2009, $16.5 million of lower earnings on investments in power projects, and $12.3 million of lower earnings from our investment in CEP, partially offset by $4.3 million in earnings related to our investment in CENG.

        Equity investment earnings increased $74.2 million in 2008 compared to 2007 primarily due to $38.0 million of higher earnings from our shipping joint venture, $34.6 million of higher earnings on investments in power projects, and $1.6 million of higher earnings from our investment in CEP.

Regulated Electric Business

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

Results

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 attributable to common stock from the regulated electric business increased $67.8 million in 2009 compared to 2008, mostly due to a $53.8 million after-tax decrease in credits provided to customers.

        Net income attributable to common stock 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 $110.5 million after-tax.

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Electric Revenues

The changes in electric revenues in 2009 and 2008 compared to the respective prior year were caused by:

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 2009 and 2008 compared to the respective prior year were:

        In 2009, we distributed less electricity to residential customers due to decreased usage per customer, partially offset by colder winter weather and an increased number of customers. We distributed less electricity to industrial customers primarily due to decreased usage per customer.

        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.

Residential Customer Rate Credit

On October 30, 2009, the Maryland PSC issued an order approving Constellation Energy's transaction with EDF. Among other things, the order required Constellation Energy to fund a one-time distribution rate credit for BGE residential customers before the end of March 2010 totaling $110.5 million, or approximately $100 per customer, for which BGE recorded a liability in November 2009. In December 2009, BGE filed a tariff with the Maryland PSC stating BGE would give residential customers a rate credit of exactly $100 per customer. As a result, BGE accrued an additional $1.9 million for a total fourth quarter 2009 accrual of $112.4 million. The portion of this total credit allocated to residential electric customers was $95.0 million pre-tax. This credit was accrued in the fourth quarter of 2009 and will be applied to BGE residential electric customer bills in the first quarter of 2010.

Nuclear Decommissioning Charges

Effective January 1, 2009, BGE and Calvert Cliffs Nuclear Power Plant Inc. (Calvert Cliffs) mutually agreed to terminate the decommissioning funds collection agent agreement, which was effective from July 1, 2000 to December 31, 2008. As a result, BGE ceased transferring funds to provide for the decommissioning of Calvert Cliffs Unit 1 and Unit 2. Calvert Cliffs retains the obligation to provide adequate assurances of funding pursuant to Nuclear Regulatory Commission requirements. Under the 2008 Maryland settlement agreement, BGE will continue to provide certain credits to residential customers and assess certain charges to all customers relating to decommissioning.

Smart Energy Savers Program^SM Surcharge

Beginning in 2009, the Maryland PSC approved customer surcharges through which BGE recovers costs associated with certain programs designed to help BGE manage peak demand and encourage customer energy conservation.

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

The Maryland PSC has allowed us to record a monthly adjustment to our electric distribution revenues from residential and small commercial customers since 2008 and for the majority of our large commercial and industrial customers since February 2009 to eliminate the effect of abnormal weather and usage patterns per customer on our electric distribution volumes, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in consumption levels. This means BGE recognizes revenues at Maryland PSC-approved levels per customer, regardless of what actual distribution volumes were for a billing period. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions. We then bill or credit impacted customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.

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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 decreased in 2009 compared to 2008 mostly due to lower standard offer service volumes, partially offset by higher standard offer service rates.

        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.

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 as a result of the expiration of the rate stabilization plans.

Rate Stabilization Recovery

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

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.

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 2008 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 2009 compared to 2008 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.

        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:

Actual Costs

BGE's actual costs for electricity purchased for resale decreased $39.2 million for 2009 compared to 2008, primarily due to lower standard offer service volumes, partially offset by higher standard offer service rates.

        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.

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. 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.

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Recovery under Rate Stabilization Plans

In late June 2007, we began recovering previously deferred amounts from customers. We recovered $59.0 million per year in 2009 and 2008 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 $18.5 million in 2009 compared to 2008, primarily due to increased uncollectible accounts receivable expense of $5.1 million and the impact of inflation on other costs of $8.0 million.

        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.

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 2009 or 2007.

Electric Depreciation and Amortization Expense

Regulated electric depreciation and amortization expense increased $33.9 million during 2009, compared to 2008, primarily due to $43.3 million in increased amortization expense associated with the Smart Energy Savers Program^SM and additional property placed in service in 2009, partially offset by $18.7 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.

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

Taxes Other Than Income Taxes

Taxes other than income taxes increased $3.8 million during 2009 compared to 2008, primarily due to the impact of $94.1 million pre-tax in lower customer credits on franchise taxes.

Regulated Gas Business

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

Results

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 attributable to common stock from the regulated gas business decreased $14.7 million in 2009 compared to 2008, primarily due to the accrual of a customer rate credit of $10.4 million after-tax and increased operations and maintenance expenses of $2.2 million after-tax.

        Net income attributable to common stock 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.

Gas Revenues

The changes in gas revenues in 2009 and 2008 compared to the respective prior year were caused by:

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