10-K 1 a2207433z10-k.htm 10-K

Table of Contents



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

FORM 10-K


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

For the fiscal year ended DECEMBER 31, 2011

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


1-12869

 

CONSTELLATION ENERGY GROUP, INC.

 

52-1964611

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

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

1-1910   BALTIMORE GAS AND ELECTRIC COMPANY   52-0280210

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:

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

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

 

)

 

New York Stock Exchange

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

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

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

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

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

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

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

          Indicate by check mark whether Constellation Energy Group, Inc. 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 ý    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, 2011 was approximately $7,621,809,578 based upon New York Stock Exchange composite transaction closing price.

CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE
201,878,759 SHARES OUTSTANDING ON JANUARY 31, 2012.

DOCUMENTS INCORPORATED BY REFERENCE

Part of Form 10-K
 
Document Incorporated by Reference
III   Certain sections of the Proxy Statement for the 2012 Annual Meeting of Shareholders for Constellation Energy Group, Inc.

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




TABLE OF CONTENTS

 
   
   
  Page  
        Forward Looking Statements     1  
PART I                

Item 1

    Business     2  
                Overview     2  
                Generation Business     3  
                NewEnergy Business     4  
                Baltimore Gas and Electric Company     8  
                Consolidated Capital Requirements     12  
                Environmental Matters     12  
                Employees     16  

Item 1A

    Risk Factors     16  

Item 2

    Properties     27  

Item 3

    Legal Proceedings     29  

Item 4

    Mine Safety Disclosure     29  
        Executive Officers of the Registrant (Instruction 3 to Item 401(b) of Regulation S-K)     29  
PART II                

Item 5

    Market for Registrant's Common Equity, Related Shareholder Matters, Issuer Purchases of Equity Securities, and Unregistered Sales of Equity and Use of Proceeds     30  

Item 6

    Selected Financial Data     31  

Item 7

    Management's Discussion and Analysis of Financial Condition and Results of Operations     33  

Item 7A

    Quantitative and Qualitative Disclosures About Market Risk     71  

Item 8

    Financial Statements and Supplementary Data     72  

Item 9

    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     164  

Item 9A

    Controls and Procedures     164  

Item 9B

    Other Information     164  
PART III                

Item 10

    Directors, Executive Officers and Corporate Governance     164  

Item 11

    Executive Compensation     164  

Item 12

    Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters     165  

Item 13

    Certain Relationships and Related Transactions, and Director Independence     165  

Item 14

    Principal Accountant Fees and Services     165  
PART IV                

Item 15

    Exhibits and Financial Statement Schedules     166  

Signatures

    173  

Table of Contents


Forward Looking Statements

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

    the timing and extent of changes in commodity prices and volatilities for energy and energy-related products including coal, natural gas, oil, electricity, nuclear fuel, 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 to successfully invest in new business initiatives and markets,
    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 NewEnergy business and to adequately forecast their energy usage,
    the timing and extent of customer choice 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 competition, 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 our generating facilities, BGE's transmission and distribution facilities, or our other commercial operations, 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, acts of war, 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,
    cost and other effects of legal and administrative proceedings and other events that may not be covered by insurance, including environmental liabilities and liabilities associated with catastrophic events, and
    the likelihood and timing of the completion of the pending merger with Exelon Corporation, the terms and conditions of any required regulatory approvals of the pending merger, and potential diversion of management's time and attention from our ongoing business during this time period.

        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 generation business (Generation), a customer supply business (NewEnergy), 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 Generation business develops, owns, owns interests in, and operates electric generation facilities and a fuel processing facility located in various regions of the United States and Canada. This business also includes an operation that manages certain contractually controlled physical assets, including generating facilities and owns an interest in a joint venture that owns and operates nuclear generating facilities.

        Our NewEnergy business is primarily a competitive provider of energy-related products and services for a variety of customers and focuses on selling electricity, natural gas, and other energy-related products to serve customers' requirements (load-serving), and providing other energy products and risk management services. This business also manages our upstream natural gas activities, designs, constructs, and operates renewable energy, heating, cooling, and cogeneration facilities and provides home improvements, sales of electric and gas appliances, and servicing of heating, air conditioning, plumbing, electrical, and indoor air quality systems.

        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.

        On April 28, 2011, Constellation Energy entered into an Agreement and Plan of Merger with Exelon Corporation (Exelon). At closing, each issued and outstanding share of common stock of Constellation Energy will be cancelled and converted into the right to receive 0.93 shares of common stock of Exelon, and Constellation Energy will become a wholly owned subsidiary of Exelon.

        The merger agreement contains certain termination rights for both Constellation Energy and Exelon. Under narrow specified circumstances in which the merger agreement is terminated and another acquisition proposal is accepted, Constellation Energy may be required to pay Exelon a termination fee of $200 million and Exelon may be required to pay Constellation Energy a termination fee of $800 million.

        In connection with the proposed merger, Exelon and Constellation Energy offered numerous commitments, each of which is contingent upon completion of the merger, in support of their request for approval of the merger with the Maryland Public Service Commission (Maryland PSC). In addition, in December 2011, Exelon, Exelon Energy Delivery Company, LLC, Constellation Energy, and BGE entered into a settlement agreement with the State of Maryland, the Maryland Energy Administration, the City of Baltimore and the Baltimore Building and Construction Trades Council, in which they agreed to several additional commitments contingent upon completion of the merger.

        In January 2012, Exelon, Exelon Energy Delivery Company, LLC, Constellation Energy, and BGE entered into a settlement agreement with EDF Group and affiliates (EDF) in which, subject to the consummation of the merger with Exelon, the parties agreed to amendments to the operating agreement of Constellation Energy Nuclear Group, LLC, a nuclear joint venture between Constellation Energy and EDF, an existing Administrative Services Agreement (ASA) and an existing Power Services Agency Agreement (PSA). We discuss the ASA and PSA in more detail in Note 16 to the Consolidated Financial Statements.

        The merger agreement has been approved by the boards of directors and stockholders of both Constellation Energy and Exelon and by several other state and federal regulatory bodies. The parties are working to complete the merger in the first quarter of 2012 absent any Federal Energy Regulatory Commission approval delays.


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.

 
  Unaffiliated Revenues  
 
  Generation   NewEnergy   Regulated
Electric
  Regulated
Gas
  Holding
Company
and
Other
 

2011

    8 %   70 %   17 %   5 %   %

2010

    8     68     19     5      

2009

    4     73     18     5      

 

 
  Net (Loss) Income Attributable to Common Stock  
 
  Generation   NewEnergy   Regulated
Electric
  Regulated
Gas
  Holding
Company
and
Other
 

2011

    (130 )%   (5 )%   25 %   11 %   (1 )%

2010

    (128 )   14     10     4      

2009

    107     (9 )   1     1      


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  Total Assets  
 
  Generation   NewEnergy   Regulated
Electric
  Regulated
Gas
  Holding
Company
and
Other
  Eliminations  

2011

    45 %   21 %   28 %   8 %   4 %   (6 )%

2010

    49     19     26     7     4     (5 )

2009

    53     18     21     6     19     (17 )


Generation Business

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, hold interests in qualifying facilities, and power projects in the United States and Canada totaling 11,751 MW as of December 31, 2011, and manage approximately 1,100 MW associated with certain of our long-dated tolling agreements. These agreements provide us with the contractual rights to purchase power from third party generation plants over an extended period of time. The output of our owned and contractually controlled plants is managed by our NewEnergy business 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 NewEnergy 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 Constellation Energy Nuclear Group LLC and affiliates (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:

 
  Calvert Cliffs   Nine Mile Point   Ginna  
 
  MWH   Capacity
Factor
  MWH (1)   Capacity
Factor
  MWH   Capacity
Factor
 
 
  (MWH in millions)
 

2011

    14.4     96 %   12.4     91 %   4.3     85 %

2010

    14.0     94     12.6     93     4.9     97  

2009

    14.5     96     13.1     97     4.6     91  
(1)
Represents our and CENG's (after November 6, 2009) proportionate ownership interest

        We have a unit contingent power purchase agreement (PPA) with CENG under which we purchase 85 to 90% of the output of CENG's nuclear plants that is not sold to third parties under pre-existing PPAs through 2014. Beginning on January 1, 2015, and continuing to the end of the lives of the respective nuclear plants, we will purchase 50.01% and EDF will purchase 49.99% of the output of CENG's nuclear plants. 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.

        Nine Mile Point Unit 2 sold 90% of the plant's output to the former owners of the plant at an average price of approximately $35 per MWH under a PPA that terminated in November 2011. The PPA was unit contingent. (Under a unit contingent contract, 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 was managed by CENG and sold primarily to us and EDF.

        After expiration of the Nine Mile Point Unit 2 PPA, a revenue sharing agreement with the former owners of the plant began and will 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


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remaining 10% of the output of Ginna is managed by CENG and sold primarily to us and EDF.

Qualifying Facilities and Power Projects

We hold up to a 50% voting interest in 15 operating energy projects, totaling approximately 758 MW, that consist of electric generation (primarily relying on alternative fuel sources), fuel processing, or fuel handling facilities. Thirteen 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.

Contracted Generation

We manage approximately 1,100 MWs under three agreements with third party generators in which we have long-dated contractual rights to purchase power from these third party generating plants. The economics of these transactions are similar to our owned generation.


NewEnergy Business

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

        To meet our customers' requirements, our NewEnergy business obtains energy from various sources, including:

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

        During 2011, our NewEnergy business:

    supplied approximately 131 million megawatt hours (MWH) of aggregate electricity to distribution utilities, municipalities, and residential, commercial, industrial, and governmental customers,
    provided approximately 330 million mmBTUs (million British Thermal Units) of natural gas to residential, commercial, industrial, and governmental customers,
    delivered approximately 5.5 million tons of coal primarily to our own fleet, and
    delivered approximately 213 million mmBTUs of natural gas to our fleet of owned and contracted generation assets.

        Our NewEnergy business also manages certain contractually controlled physical assets, including generation facilities (excluding long-dated tolling agreements managed by our Generation business), and natural gas properties, provides risk management services, and trades energy and energy-related commodities. This business also provides the wholesale risk management function for our Generation business, as well as structured products and energy investment activities and includes our actual hedged positions with third parties.

        Our NewEnergy business also manages our upstream natural gas activities, designs, constructs, and operates renewable energy, heating, cooling, and cogeneration facilities and provides home improvements, sales of electric and gas appliances, and servicing of heating, air conditioning, plumbing, electrical, and indoor air quality systems.

Wholesale Customer Supply

In 2011, our wholesale NewEnergy customer supply operation served approximately 62 million MWHs of wholesale full requirements electricity and related load-serving products.

        Our wholesale NewEnergy 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 have in-house supply functions to meet their own load requirements.

Retail Customer Supply

During 2011, our retail NewEnergy customer supply operation served approximately 69 million MWHs of electricity load and approximately 330 mmBTUs of natural gas. Our volume served in 2011 increased compared to the prior year as a result of the acquisition of Star Electricity, Inc. (StarTex) (May 2011) and MXenergy Holdings Inc. (MXenergy) (July 2011). We discuss these acquisitions in more detail in Note 15 to Consolidated Financial Statements.

        Our retail NewEnergy customer supply operation structures transactions to supply full energy and capacity requirements and provide natural gas, transportation, and other energy products and services to commercial, industrial, governmental, and residential customers. Contracts with these customers generally extend from one to ten years, but some can be longer.

        The retail NewEnergy customer supply operation combines a unified sales force with a customer-centric model that leverages technology to broaden the range of products and services we offer, which we believe promotes stronger customer relationships. This model focuses on efficiency and cost reduction, which we believe will provide a platform that is scalable and able to capitalize on opportunities for future growth.


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Structured Products

Our NewEnergy business 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 NewEnergy business assists customers with customized risk management products in the power, gas, coal, and freight markets (e.g., generation tolls and gas transport and storage).

Energy Investments

Our NewEnergy business has investments in energy assets that primarily include natural gas activities. Our NewEnergy business includes upstream (exploration and production) and downstream (transportation and storage) natural gas operations. Our upstream natural gas activities include the development, exploration, and exploitation of natural gas properties. During 2011, we sold substantially all of our interests in Constellation Energy Partners LLC (CEP), a company formed by us and principally engaged in the acquisition, development, and exploitation of natural gas properties, to PostRock Energy Corporation. We do not have any involvement in the day-to-day operations of CEP. We discuss the sale of our interests in CEP in more detail in Note 2 to Consolidated Financial Statements.

Portfolio Management and Trading

Our NewEnergy business 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 NewEnergy business, along with daily value at risk limits, 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 NewEnergy business to:

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

        We discuss the impact of our trading activities and 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).

        Our energy trading activities are being used primarily for hedging our Generation and NewEnergy businesses, price discovery and verification, and for deploying limited risk capital.

Fuel Sources

Our power plants use diverse fuel sources. Our plants' fuel mix based on capacity owned at December 31, 2011 and actual output by fuel type during 2011 was as follows:

Fuel
  Capacity
Owned
  Generation  

Nuclear (1)

    16 %   30 %

Coal

    23     24  

Natural Gas

    42     41  

Oil

    6      

Renewable and Alternative (2)

    5     5  

Dual (3)

    8      
(1)
Reflects our 50.01% ownership interest in CENG.

(2)
Includes solar, 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.


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

    purchase of uranium (concentrates and uranium hexafluoride),
    conversion of uranium concentrates to uranium hexafluoride,
    enrichment of uranium hexafluoride (enrichment services and enriched uranium hexafluoride), and
    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

The Nuclear Waste Policy Act of 1982, as amended, ("NWPA") requires 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. Although the NWPA and CENG's contracts with the DOE required the DOE to begin taking possession of spent nuclear fuel no later than January 31, 1998, the DOE has thus far failed to meet its obligation. The DOE's delay in taking possession of spent fuel has required CENG to undertake additional actions and incur costs to provide on-site dry fuel storage at all three of its nuclear sites. CENG has installed additional capacity at its independent spent fuel storage installation ("ISFSI") at Calvert Cliffs and Ginna, and is constructing an ISFSI to be placed in service at Nine Mile Point in 2012.

        Prior to 2010, the DOE had stated that it may not meet its obligation until 2020 at the earliest. During 2010, the DOE requested the withdrawal of its license application to use Yucca Mountain as a national repository for spent nuclear fuel. At this time, CENG is not able to determine whether the DOE will be able to commence meeting its obligation by 2020.

        Each of CENG's plant subsidiaries have filed complaints against the federal government in the U.S. 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. Any funds received from the DOE that represent the settlement of claims incurred prior to November 6, 2009, the date we sold a 49.99% membership interest in CENG to EDF, will belong to Constellation Energy, and any funds representing the settlement of claims incurred after November 6, 2009 will belong to CENG. During 2011, CENG executed settlement agreements with the DOE that detail a framework and procedure for recovery of damages incurred or to be incurred through the end of 2013 at the Calvert Cliffs and Ginna nuclear power plants. Constellation Energy, through its share of the settlement proceeds, received the following amounts in 2011for costs incurred through November 6, 2009 to store spent nuclear fuel:

    $39.4 million related to costs at the Calvert Cliffs nuclear power plant, and
    $54.4 million related to costs at the Ginna nuclear power plant.

        The lawsuit relating to the storage of spent nuclear fuel at the Nine Mile Point power plant remains outstanding.

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 permanently cease operation.

        Decommissioning activities are currently projected to be staged through the 2080 decade. 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 by CENG. CENG has the ability to request funding assistance from both Constellation Energy and EDF, as the owners of CENG.

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 were 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. 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. We


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believe that we will be able to renew supply contracts as they expire or enter into contracts with other coal suppliers. Our primary coal-burning facilities have the following requirements:

 
  Approximate
Annual Coal
Requirement
(tons)
 

Brandon Shores—Units 1 and 2 (combined)

    2,450,000  

C. P. Crane—Units 1 and 2 (combined) (1)

    650,000  

H. A. Wagner—Units 2 and 3 (combined)

    600,000  
(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 using sub-bituminous coal from the Western United States 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 (NOx), 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 was converted to burn up to 100% sub-bituminous coal in June 2010. In March 2010, we completed installation of flue gas desulfurization (FGD) equipment on both Brandon Shores units. With the FGD installation, Brandon Shores now is able to burn higher sulfur coals (limit 6 lbs/mmbtu or approximately 3.5% sulfur) while simultaneously reducing station emissions. 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. 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 expected 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.

        In connection with the merger with Exelon, we have committed to sell three coal plants: Brandon Shores, C.P. Crane, and H.A. Wagner, within six months of the completion of the merger.

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

Our requirements for residual fuel oil (No. 6) amount 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


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

        We face competition in the retail and wholesale market for energy, capacity, and ancillary services. In our NewEnergy business, we compete with international, national, and regional full-service energy providers, merchants, and producers to obtain and supply competitively priced products 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, and innovation of our products.

        With respect to our Generation business, 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.

        Many states are considering different types of regulatory initiatives concerning competition in the power and gas industry, which makes a general assessment of the state of competitive markets difficult. Many states continue to support or expand retail competition and industry restructuring. Other states that were considering restructuring have slowed their plans or postponed consideration of competitive markets. In addition, states that have restructured their energy markets routinely consider new market rules that could result in more limited opportunities for competitive energy suppliers like Constellation Energy. While some uncertainty remains in this area, we believe there is adequate growth potential in the current competitive market along with some probability of more markets opening to competition.

        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 power prices compared to the rates charged by local utilities affects the contract margin we receive from our customers. With sustained low forward natural gas and power prices and low market volatility, overall margins have tightened as competitors have aggressively pursued market share. We continue to expand our product offerings and customer service experience to support renewals and grow our customer base. 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 conditions.

Generation and NewEnergy Operating Statistics

 
  2011
  2010
  2009
 
   

Gross Margin (In millions)

                   

Generation (1)

  $ 951   $ 800   $ 2,082  

NewEnergy

    1,049     1,244     1,079  
   

Total Gross Margin

  $ 2,000   $ 2,044   $ 3,161  
   

Generation (In millions)—MWH (1)(2)

    51.3     35.1     46.0  
   

Operating statistics do not reflect the elimination of intercompany transactions.

(1)
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. These amounts also exclude contracted generation.

(2)
These amounts exclude contracted generation.



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.


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Electric Business

Electric Competition

Maryland has implemented electric customer choice and competition among electric suppliers. As a result, all customers can choose their electric energy supplier, which includes subsidiaries of Constellation Energy. 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 from June 1, 2008 through May 31, 2010 without having to rebate it to all residential electric customers. Starting June 1, 2010, BGE provides all residential electric customers a credit for the residential return component of the administrative charge through December 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 terms of three months or two years.

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

Residential customers went to full market rates in January 2008. Pursuant to the order issued by the Maryland PSC in October 2009 approving our transaction with EDF, BGE, in 2010, provided rate credits totaling $112.4 million to it s residential customers. 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.

        In 2010, the Maryland PSC issued a rate order authorizing BGE to increase electric and gas distribution rates for service rendered on or after December 4, 2010 by no more than $31.0 million for electric distribution rates and by no more than $9.8 million for gas distribution rates. We discuss this rate order in more detail in Item 7. Management's Discussion and Analysis—Regulation—Maryland—Base Rates section.

Electric Load Management

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

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

        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 August 2010, the Maryland PSC approved a comprehensive smart grid initiative for BGE which includes the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of approximately $480 million. Under a grant from the DOE, BGE is a recipient of $200 million in federal funding for our smart grid and other related initiatives. This grant allows BGE to be reimbursed for smart grid and other related expenditures up to $200 million, substantially reducing the total cost of these initiatives. As of December 31, 2011, BGE has received approximately $95.3 million of the $200 million grant from the DOE. If BGE fails to meet its obligation to incur certain costs under the DOE grant or BGE's completion of the smart grid initiative is delayed beyond approved DOE grant deadlines for incurring costs under the grant program, BGE's grant could be impacted, which could substantially increase the total cost for these initiatives.

        The Maryland PSC initially approved a full portfolio of conservation programs for implementation in 2009 for a three year period through 2011 as well as a customer surcharge to recover the associated costs. This customer surcharge is updated annually. In December 2011, the Maryland PSC approved BGE's conservation programs for implementation in 2012 through 2014 as well as the annual update to the 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 24,800 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

 
  2011
  2010
  2009
 
   

Revenues (In millions)

                   

Residential

                   

Excluding Delivery Service Only

  $ 1,347.4   $ 1,808.6   $ 1,864.0  

Delivery Service Only

    108.1     48.1     14.3  

Commercial

                   

Excluding Delivery Service Only

    387.3     467.4     531.2  

Delivery Service Only

    275.1     249.5     245.0  

Industrial

                   

Excluding Delivery Service Only

    22.5     28.7     30.4  

Delivery Service Only

    29.0     25.6     29.1  
   

System Sales and Deliveries

    2,169.4     2,627.9     2,714.0  

Other (1)

    152.0     124.4     106.7  
   

Total

  $ 2,321.4   $ 2,752.3   $ 2,820.7  
   

Distribution Volumes (In thousands)—MWH

                   

Residential

                   

Excluding Delivery Service Only

    9,821     12,344     12,394  

Delivery Service Only

    2,831     1,490     457  

Commercial

                   

Excluding Delivery Service Only

    3,259     3,707     3,945  

Delivery Service Only

    13,220     12,537     11,753  

Industrial

                   

Excluding Delivery Service Only

    215     267     270  

Delivery Service Only

    2,463     2,519     2,757  
   

Total

    31,809     32,864     31,576  
   

Customers (In thousands)

                   

Residential

    1,116.4     1,114.7     1,111.9  

Commercial

    118.9     118.6     118.5  

Industrial

    5.8     5.5     5.3  
   

Total

    1,241.1     1,238.8     1,235.7  
   
(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. 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

 
  2011
  2010
  2009
 
   

Revenues (In millions)

                   

Residential

                   

Excluding Delivery Service Only

  $ 383.3   $ 427.0   $ 460.7  

Delivery Service Only

    31.6     22.1     19.0  

Commercial

                   

Excluding Delivery Service Only

    103.9     109.0     129.1  

Delivery Service Only

    40.9     39.8     40.4  

Industrial

                   

Excluding Delivery Service Only

    4.6     5.2     6.4  

Delivery Service Only

    15.7     16.7     15.2  
   

System Sales and Deliveries

    580.0     619.8     670.8  

Off-System Sales

    81.8     79.8     81.1  

Other

    9.9     9.8     6.4  
   

Total

  $ 671.7   $ 709.4   $ 758.3  
   

Distribution Volumes (In thousands)—DTH

                   

Residential

                   

Excluding Delivery Service Only

    33,680     37,791     37,889  

Delivery Service Only

    5,983     4,857     4,270  

Commercial

                   

Excluding Delivery Service Only

    11,098     11,606     12,066  

Delivery Service Only

    26,446     24,329     25,046  

Industrial

                   

Excluding Delivery Service Only

    540     595     635  

Delivery Service Only

    17,053     19,750     20,826  
   

System Sales and Deliveries

    94,800     98,928     100,732  

Off-System Sales

    16,436     14,711     17,542  
   

Total

    111,236     113,639     118,274  
   

Customers (In thousands)

                   

Residential

    608.9     608.6     606.8  

Commercial

    43.1     42.9     42.9  

Industrial

    1.1     1.1     1.1  
   

Total

    653.1     652.6     650.8  
   

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.


Consolidated Capital Requirements

Our total capital requirements, excluding acquisitions, for 2011 were $1.2 billion. Of this amount, $0.5 billion was used in our Generation and NewEnergy businesses and $0.7 billion was used in our regulated business. We estimate our total capital requirements will be $1.2 billion in 2012.

        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.


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        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 $1.2 billion during the five-year period 2007-2011 to comply with existing environmental standards and regulations, including the Maryland Healthy Air Act (HAA). Our estimated environmental capital requirements for the next three years are approximately $20 million in 2012, $30 million in 2013, and $40 million in 2014.

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, sulfur dioxide (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 nitrogen oxide (NOx) emissions from fossil fuel-fired generating facilities located primarily in the Eastern United States. Following a court order to reconsider the CAIR requirements, the EPA adopted the Cross-State Air Pollution Rule (CSAPR) in July 2011 to replace CAIR with a program that would have required each of 31 Eastern states and the District of Columbia to reduce SO2 and NOx emissions beginning January 1, 2012. In December 2011, the United States Court of Appeals for the District of Columbia Circuit granted a request to stay the effectiveness of CSAPR, which reinstated the CAIR requirements while the court considers CSAPR.

        Neither the reinstatement of CAIR nor the potential adoption of CSAPR result in a material change to our emissions reduction plan in Maryland as the magnitude and timing of the emissions reduction requirements of Maryland's HAA and Clean Power Rule (CPR) are generally consistent with the requirements of CSAPR and CAIR. However, if CSAPR is implemented, it could affect the market prices of SO2 and NOx emission allowances, which could in turn affect our financial results.

Other NAAQS Rulemaking

In January 2010, the EPA proposed rules to adopt NAAQS for ozone that are stricter than the NAAQS adopted in March 2008, based on the EPA's reevaluation of scientific evidence about ozone and ozone's effects on humans and the environment. The final standard is not expected to be adopted before 2014.

        In June 2010, the EPA adopted a stricter NAAQS for SO2. States will need to submit plans by June 2013 demonstrating attainment of the new standard by 2017.

        In September 2006, the EPA adopted a stricter NAAQS for particulate matter. States will need to submit plans in 2012 demonstrating attainment of the new standard by 2014.

        We are unable to determine the impact that complying with the stricter NAAQS for ozone, SO2, or particulate matter will have on our financial results until the states in which our generating facilities are located adopt plans to meet the new standards. However, costs associated with compliance with these plans could be material.

Section 185 Fees

In December 2006, the United States Court of Appeals for the District of Columbia Circuit ruled that requirements to impose fees on large emissions sources in areas that have not attained the NAAQS 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. Guidance issued by the EPA to the states dated January 2010 that contained flexible state alternatives to meet the Section 185 fee requirements was vacated by the court in July 2011. As a result, states in which we operate have not finalized their approach for implementing the requirements and consequently, and 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.

Mercury and Air Toxics Standards

In December 2011, the EPA established hazardous air pollutant emission standards for existing fossil fuel-fired power generating facilities. These standards establish technology-based emissions limits for mercury and other toxic air pollutants based on the emissions reductions achieved by the best performing emission sources currently in operation. Facilities subject to the new standards must achieve compliance by 2015. An additional year to achieve compliance will be available to facilities that are unable to meet the three-year deadline without adversely affecting the reliability of the United States electric system. The magnitude and timing of the emissions reduction requirements under the new standards are consistent with those under


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Maryland's HAA and CPR and, as a result, we do not expect our compliance costs to be material.

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 Keystone and Conemaugh, two of our newer Pennsylvania 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 20.99% interest, performed various capital projects without complying with the new source review requirements.

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

State

Maryland has adopted the HAA and the CPR, which establish annual SO2, NOx, and mercury emission caps for specific coal-fired units in Maryland, including units located at three of our facilities. The requirements of the HAA and the CPR for SO2, NOx, and mercury emissions are generally consistent with existing and anticipated federal requirements. Likewise, Massachusetts has comprehensive air emissions standards in place that are more stringent than the federal standards, so impending regulations are not anticipated to cause additional costs to our natural gas and oil-fired units in Massachusetts. In Pennsylvania, regulations adopted requiring coal-fired generating facilities to reduce mercury emissions were ruled invalid by a Pennsylvania court in January 2009.

        Maryland has also adopted opacity regulations consistent with its commitment to resolve long-standing industry concerns about the prior regulations' continuous compliance requirements and is in the process of obtaining the EPA's approval of Maryland's state implementation plan (SIP) for these regulations. While EPA approval of Maryland's SIP is being obtained, the opacity regulations are being implemented in a manner that will enable our plants to remain in compliance. We anticipate that the regulations under the EPA-approved SIP will be approved as currently implemented.

Capital Expenditure Estimates—Air Quality

We expect to incur additional environmental capital spending as a result of complying with the air quality laws and regulations discussed above. To comply with HAA and CPR, we will install additional air emission control equipment at our coal-fired generating facilities in Maryland and at our co-owned coal-fired facilities in Pennsylvania to meet air quality standards. We include in our estimated environmental capital requirements capital spending for these air quality projects, which we expect will be approximately $15 million in 2012, $30 million in 2013, $35 million in 2014 and $5 million from 2015-2016.

        Our estimates are subject to significant uncertainties including the timing of any additional federal and/or state regulations or legislation, the implementation timetables for such regulation or legislation, plant divestitures, 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 continued likelihood that greenhouse gas emissions regulation will eventually 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 was introduced in the last several United States Congress sessions but was not enacted. In September 2009, the EPA issued an "endangerment and cause or contribute finding" for greenhouse gases under the Clean Air Act and in 2010 finalized changes to its


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air construction and operating permit programs to incorporate greenhouse gases as pollutants subject to air permits. Beginning in 2011, in certain instances, additional greenhouse gas emissions resulting from the construction or modification of large facilities subject to the EPA's permit programs, which include power plants, are required to be controlled through the use of the best available control technology, as determined by the EPA, before an air emissions permit will be issued. If we were to modify our generating plants, our costs to comply with these requirements could be material depending on the modifications made. In addition, the EPA has proposed a new source performance standard for greenhouse gas emissions that, if adopted, would apply to new power generating facilities.

        Maryland and Massachusetts are participants in the Northeast Regional Greenhouse Gas Initiative (RGGI). Under RGGI, the states auction carbon dioxide (CO2) allowances associated with 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.

        In addition, California has adopted regulations to implement a cap and trade program beginning in 2013 aimed at achieving a 15% reduction in CO2 emissions by 2020 as compared with 2012. The cost of purchasing emission allowances under this program could have a material impact on our financial results depending on market prices for the allowances.

        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 also have experience trading in the markets for emissions allowances and renewable energy credits and our NewEnergy business has expertise in providing 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 eight 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 proposed new regulations in April 2011 and we will evaluate our compliance options in light of those proposed regulations. Until the new regulations are finalized, which is expected in July 2012, water intake compliance will be determined in accordance with the EPA's July 2007 order and relevant state regulations and interpretations. Depending on the scope of any new regulations that may be adopted by the EPA, our compliance costs could be material.

        In July 2011, the New York Department of Environmental Conservation (NYDEC) released a final policy regarding the best technology available for cooling water intake structures for minimizing adverse environmental impacts. Through its policy, NYDEC established closed cycle cooling or its equivalent as the performance goal for all existing facilities but also provided that NYDEC will select a feasible technology whose costs are not wholly disproportionate to the environmental benefits to be gained and allows for a site-specific determination where the performance goal cannot be achieved. CENG submissions to the NYDEC are currently under review. Once the required technology is determined and costs can be reasonably estimated, CENG will evaluate its next steps. However, such costs could be material.


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Hazardous and Solid Waste

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 began 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 was considering regulating ash as a hazardous waste. In May 2010, the EPA proposed rules to regulate coal combustion residuals (CCRs), such as ash, either as a special hazardous waste or as a nonhazardous waste. The EPA plans to issue an analysis on the potential health risks from beneficial re-use of CCRs prior to issuing a final rule, which is expected at the end of 2012. In addition, the Maryland Department of the Environment finalized regulations governing the disposal, storage, use and placement of ash in December 2008. Depending on the scope of any final rules that are adopted, additional federal regulation has the potential to result in additional compliance requirements and costs that could be material.

        As a result of these regulatory proposals and our current ash generation projections, we are constructing and have begun using a dedicated ash landfill for our Maryland coal-fired plants, while we continue to explore and develop beneficial use opportunities. Over the next five years, we estimate that our capital expenditures for the landfill will be approximately $20 million. Our estimates are subject to significant uncertainties, including the timing of any regulatory change, its implementation timetable, and the scope of the final federal and state 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 7,900 employees at December 31, 2011.


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.


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 slow recovery from recession or a new 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. Instability or volatility in the capital and credit markets as a result of uncertainty,


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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 may be exploring. In addition, such instability or volatility 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 instability or volatility 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.

As a result of participation in wholesale and retail energy markets, our NewEnergy business may incur substantial costs and liabilities through exposure to price volatility, counterparty performance risk, and competition that could negatively impact margins.

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 NewEnergy business enters into transactions with numerous third parties (commonly referred to as "counterparties"). In these arrangements, we are exposed to the credit risks of our counterparties and the risk that one or more counterparties may fail to perform under their obligations to make payments or deliver fuel or power. In addition, we enter into various wholesale transactions through Independent System Operators (ISOs). These ISOs are exposed to counterparty credit risks. Any losses relating to counterparty defaults impacting the ISOs are allocated to and borne by all other market participants in the ISO. These risks are exacerbated during periods of commodity price fluctuations. If a counterparty were to default and we were to liquidate all contracts with that entity, our credit loss would include the loss in value of derivative contracts recorded at fair value, the amount owed for settled transactions, and additional payments, if any,


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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.

        Exposure to margin and volume competition.    With sustained low forward natural gas and power prices and low market volatility, overall margins have tightened as retail competitors have aggressively pursued market share and wholesale generators have used the retail channel to hedge generation output. Tightened margins could adversely affect our financial results by decreasing our overall gross margins and profitability.

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

Our businesses are 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 Generation and NewEnergy businesses. 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 NewEnergy business, we generally do not receive collateral under contractual obligations to supply our customers, but we 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, and, 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.

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 our 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 also can be adversely affected by various factors, including price volatility and the availability of credit. 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 and NewEnergy businesses, 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.


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        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.

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

At December 31, 2011, our qualified pension obligation was approximately $225 million greater than the fair value of our plan assets. 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.

Through our nuclear joint venture, we indirectly 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;


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    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 our nuclear joint venture or another participating insured party's nuclear plants, we or CENG could be assessed retrospective insurance premiums (because all nuclear plant operators contribute to a nationwide catastrophic insurance fund). In instances where CENG is the member insured, we have guaranteed our share of CENG's performance. 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 by-products, and mandated investment in maximum achievable control technology or 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 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 competitive 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


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review or how such outcome may affect our, or BGE's financial results, but it could be material.

        The Dodd-Frank Wall Street Reform and Consumer Protection Act provides for a new regulatory regime for derivatives. Final regulations may address collateral requirements, exchange margin cash postings, and other aspects of derivative transactions, which if applicable to us despite being an end user of derivatives, could require us to post additional cash collateral or otherwise have a material adverse effect on our business.

        We are also 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. Additionally, in 2011, the State of Maryland enacted legislation that imposed reliability and quality of service standards on electric companies and requires the Maryland PSC to enact regulations by July 1, 2012 to implement these standards.

        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 competitive segments of the electric and gas industries created by federal and state restructuring initiatives. If competitive restructuring of the electric or gas industries is amended, 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.

        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. Proposals in the State of Maryland from time to time 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. In addition, other states are seeking more direct ways to affect the results of wholesale capacity markets, including through legislative or regulatory action that provides subsidies to or guaranteed cost recovery for the development of new generation in exchange for the new generation clearing in the PJM capacity market. 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 amended, reversed, discontinued, restricted, or delayed, or if legislative or regulatory 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 in Canada. As a result, we depend on transportation and transmission facilities owned and operated by utilities and other energy companies to deliver the electricity, natural gas and other related products 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 may require significant expenditures to maintain and is subject to operational failure, which could result in potential liability.

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. Operational failure could result in potential liability if such failure results in damage to property or injury to individuals. As a result, electric and gas infrastructure expenditures and operational failure of equipment could have an adverse effect on our, or BGE's, financial results.


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Our NewEnergy 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 NewEnergy 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 NewEnergy business must be prepared to supply to customers may increase our operating costs. The process of estimating the load requirements of our customers is complicated by potential variability in demand resulting from extreme changes in weather and economic factors affecting our customers. A significant under- or over-estimation of load requirements could result in our NewEnergy 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.

Investment in new business initiatives and markets may not be successful.

Our NewEnergy business has sought to invest in new business initiatives and actively participate in new markets. These include, but are not limited to, unconventional oil and gas exploration and production, residential retail power and gas sales, solar and wind generation, and managed load response. Such initiatives may involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered in the diligence performed prior to launching an initiative or entering a market. Additionally, as these markets mature, there may be new market entrants or expansion by established competitors that increase competition for customers and resources, which could result in us not achieving our plans and could have a material adverse effect on our financial results. In addition to our NewEnergy business, BGE faces risks associated with its Smart Grid initiative. These risks include, but are not limited to, cost recovery, regulatory concerns, cyber security and obsolescence of technology. Due to these risks, no assurance can be given that such initiatives will be successful and will not have a material adverse effect on our financial results.

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

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

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


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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. Specifically, we intend to continue to pursue the acquisition of new generating plants in regions where we have significant retail and wholesale customer supply operations. Acquired plants may not generate the projected rates of return or sufficiently match generation capacity with retail and wholesale customer supply operations volumes causing an increase in collateral requirements. If we cannot identify, complete and integrate acquisitions successfully, our business, results of operations and financial condition could be adversely affected.

War, threats of terrorism and catastrophic events may impact the results of our operations in unpredictable ways.

We cannot predict the impact that any future act of war, terrorist attack, or catastrophic event might 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, war, or a catastrophic event may affect our operations. Furthermore, these catastrophic events could compromise the physical or cyber security of our facilities, which could adversely affect our ability to manage our business 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 war, threats of terrorism, and catastrophic events may affect our stock price and our ability to raise capital.

        In addition, we maintain a level of insurance coverage consistent with industry practices against property and casualty losses subject to unforeseen occurrences or catastrophic events that may damage or destroy assets or interrupt operations. Furthermore, in the event of a severe disruption resulting from war, threats of terrorism, and catastrophic events, we have contingency plans and employ crisis management to respond and recover operations. Despite these measures, there may be events beyond our control that may severely impact operations and affect financial performance.

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

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 NewEnergy business, 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.

Our employees, contractors, customers, and the general public may be exposed to a risk of injury due to the nature of the energy industry.

Employees and contractors throughout the organization work in, and customers and the general public may be exposed to, potentially dangerous conditions near our operations. As a result, employees, contractors, customers, and the general public may be at risk for serious injury, including loss of life. Significant risks include nuclear accidents, gas explosions, and electric contact cases.


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Because the market price of shares of Exelon common stock will fluctuate and the exchange ratio will not be adjusted to reflect such fluctuations, the merger consideration at the date of the closing may vary significantly from the date the merger agreement was executed.

Upon completion of the merger, each outstanding share of Constellation Energy common stock will be converted into the right to receive 0.93 of a share of Exelon common stock. The number of shares of Exelon common stock to be issued pursuant to the merger agreement for each share of Constellation Energy common stock will not change to reflect changes in the market price of Exelon or Constellation Energy common stock. The market price of Exelon common stock at the time of completion of the merger may vary significantly from the market prices of Exelon common stock on the date the merger agreement was executed.

        In addition, we might not complete the merger until a significant period of time has passed after the respective special shareholder meetings. Because Exelon will not adjust the exchange ratio to reflect any changes in the market value of Exelon common stock or Constellation Energy common stock, the market value of the Exelon common stock issued in connection with the merger and the Constellation Energy common stock surrendered in connection with the merger may be higher or lower than the values of those shares on earlier dates. Stock price changes may result from market reaction to the announcement of the merger and market assessment of the likelihood that the merger will be completed, changes in the business, operations or prospects of Exelon or Constellation Energy prior to or following the merger, litigation or regulatory considerations, general business, market, industry or economic conditions and other factors both within and beyond the control of Exelon and Constellation Energy. Neither we nor Exelon is permitted to terminate the merger agreement solely because of changes in the market price of either company's common stock.

The merger agreement contains provisions that limit each of Exelon's and Constellation Energy's ability to pursue alternatives to the merger, which could discourage a potential acquirer of either Constellation Energy or Exelon from making an alternative transaction proposal and, in certain circumstances, could require Exelon or Constellation Energy to pay to the other a significant termination fee.

Under the merger agreement, we and Exelon are restricted, subject to limited exceptions, from entering into alternative transactions in lieu of the merger. In general, unless and until the merger agreement is terminated, both we and Exelon are restricted from, among other things, soliciting, initiating, knowingly encouraging or facilitating a competing acquisition proposal from any person. Each of the Exelon board of directors and the Constellation Energy board of directors is limited in its ability to change its recommendation with respect to the merger-related proposals. We or Exelon may terminate the merger agreement and enter into an agreement with respect to a superior proposal only if specified conditions have been satisfied, including compliance with the non-solicitation provisions of the merger agreement. These provisions could discourage a third party that may have an interest in acquiring all or a significant part of Exelon or Constellation Energy from considering or proposing such an acquisition, even if such third party were prepared to pay consideration with a higher per share cash or market value than the consideration proposed to be received or realized in the merger, or might result in a potential competing acquirer proposing to pay a lower price than it would otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances. Under the merger agreement, if the merger agreement is terminated and another acquisition proposal is accepted, we or Exelon, as applicable, may be required to pay a termination fee of $800 million in the case of a termination fee payable by Exelon to us and a termination fee of $200 million in the case of a termination fee payable by us to Exelon.

Exelon and Constellation Energy are subject to various uncertainties and contractual restrictions while the merger is pending that may cause disruption and could adversely affect their financial results.

Uncertainty about the effect of the merger on employees, suppliers and customers may have an adverse effect on us and/or Exelon. These uncertainties may impair our and/or Exelon's ability to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter, as employees and prospective employees may experience uncertainty about their future roles with the combined company, and could cause customers, suppliers and others who deal with us or Exelon to seek to change existing business relationships with us or Exelon. The pursuit of the merger and the preparation for the integration may also place a burden on management and internal resources. Any significant diversion of management attention away from ongoing business concerns and any difficulties encountered in the transition and integration process could affect our and/or Exelon's financial results.

        In addition, the merger agreement restricts each of Exelon and Constellation Energy, without the other's consent, from making certain acquisitions and taking other specified actions while the merger is pending. These restrictions may prevent Exelon and/or Constellation Energy from pursuing otherwise attractive business opportunities and making other changes to their respective businesses prior to completion of the merger or termination of the merger agreement.


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If completed, the merger may not achieve its anticipated results, and Exelon and Constellation Energy may be unable to integrate their operations in the manner expected.

We entered into the merger agreement with the expectation that the merger will result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of Exelon and Constellation Energy can be integrated in an efficient, effective and timely manner.

        It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of each company's ongoing businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect the combined company's ability to achieve the anticipated benefits of the merger as and when expected. The combined company's results of operations could also be adversely affected by any issues attributable to either company's operations that arise or are based on events or actions that occur prior to the closing of the merger. The companies may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect the combined company's future business, financial condition, operating results and prospects.

Pending litigation against Exelon and Constellation Energy could result in an injunction preventing the completion of the merger or a judgment resulting in the payment of damages in the event the merger is completed and may adversely affect the combined company's business, financial condition or results of operations and cash flows following the merger.

Twelve purported class action lawsuits were filed against us, each member of our board of directors, Exelon and Bolt Acquisition Corporation, a Maryland corporation and a wholly owned subsidiary of Exelon, in connection with the merger. Among other things, the lawsuits sought injunctive relief that would have prevented completion of the merger in accordance with the terms of the merger agreement. The parties to the litigation have reached a settlement that remains subject to court approval. If the settlement is not approved by the court, these lawsuits could prevent or delay completion of the merger and result in substantial costs to us and Exelon, including any costs associated with the indemnification of directors and officers. Plaintiffs may file additional lawsuits against us, Exelon and/or the directors and officers of either company in connection with the merger. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger is completed may adversely affect the combined company's business, financial condition, results of operations and cash flows.

The merger is subject to the receipt of consent or approval from governmental entities that could delay the completion of the merger or impose conditions that could have a material adverse effect on the combined company or that could cause abandonment of the merger.

Completion of the merger remains conditioned upon the receipt of consents, orders, approvals or clearances from the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission (NRC), and the Maryland PSC. The special meetings of the shareholders of Exelon and Constellation Energy at which the proposals required to complete the merger were considered took place before all of the required regulatory approvals had been obtained and before all conditions to such approvals, if any, were known.

        We and Exelon may subsequently agree to conditions without seeking further shareholder approval, such as the settlement agreements reached in December 2011 and January 2012, even if such conditions could have an adverse effect on us, Exelon, or the combined company.

        We cannot provide assurance that we and Exelon will obtain all required regulatory consents or approvals or that these consents or approvals will not contain terms, conditions or restrictions that would be detrimental to the combined company after the completion of the merger. The merger agreement generally permits each party to terminate the merger agreement if the final terms of any of the required regulatory consents or approvals require (1) any action that involves divesting, holding separate or otherwise transferring control over any nuclear or hydroelectric or pumped-storage generation assets of the parties or any of their respective subsidiaries or affiliates; or (2) any action (including any action that involves divesting, holding separate or otherwise transferring control over base-load capacity), without including those actions proposed by the parties' mutually agreed-upon analysis of mitigation to address the increased market concentration resulting from the merger and the concessions announced by the parties in the press release announcing the merger agreement, which would, individually or in the aggregate, reasonably be expected to have a material adverse effect on either party. Any substantial delay in obtaining satisfactory approvals, receipt of proceeds from required divestitures in an amount substantially lower than anticipated or the imposition of any terms or conditions in connection with such approvals could cause a material reduction in the expected benefits of the merger. If any such delays or conditions are serious enough, the parties may decide to abandon the merger.


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If completed, the merger may adversely affect the combined company's ability to attract and retain key employees.

Current and prospective Exelon and Constellation Energy employees may experience uncertainty about their future roles at the combined company following the completion of the proposed merger. In addition, current and prospective Exelon and Constellation Energy employees may determine that they do not desire to work for the combined company for a variety of possible reasons. These factors may adversely affect the combined company's ability to attract and retain key management and other personnel.

Failure to complete the merger could negatively affect our share price and our future business and financial results.

Completion of the merger is not assured and is subject to risks, including the risks that approval of the transaction by shareholders of Exelon and Constellation Energy or by governmental agencies will not be obtained or that certain other closing conditions will not be satisfied. If the merger is not completed, our ongoing business may be adversely affected and we will be subject to several risks, including:

    having to pay certain significant costs relating to the merger without receiving the benefits of the merger, including, in certain circumstances, a termination fee of $200 million to Exelon;
    the potential loss of key personnel during the pendency of the merger as employees may experience uncertainty about their future roles with the combined company;
    we will have been subject to certain restrictions on the conduct of our business, which may have prevented us from making certain acquisitions or dispositions or pursuing certain business opportunities while the merger is pending; and
    our share price may decline to the extent that the current market prices reflect an assumption by the market that the merger will be completed.

Exelon and Constellation Energy may incur unexpected transaction fees and merger-related costs in connection with the merger.

We and Exelon expect to incur a number of non-recurring expenses, totaling approximately $150 million, associated with completing the merger, as well as expenses related to combining the operations of the two companies. The combined company may incur additional unanticipated costs in the integration of the businesses of Exelon and Constellation Energy. Although we expect that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction and merger-related costs over time, the combined company may not achieve this net benefit in the near term, or at all.

Current Constellation Energy stockholders will have a reduced ownership and voting interest after the merger.

Exelon will issue or reserve for issuance approximately 201.9 million shares of Exelon common stock to Constellation Energy stockholders in the merger (including shares of Exelon common stock issuable pursuant to Constellation Energy stock options and other equity-based awards). Based on the number of shares of common stock of Exelon and Constellation Energy outstanding on October 7, 2011, the record date for the two companies' special meetings of shareholders to approve the merger, upon the completion of the merger, former Constellation Energy stockholders would own approximately 22% of the outstanding shares of Exelon common stock immediately following the consummation of the merger.

        Constellation Energy stockholders currently have the right to vote for our directors and on other matters affecting us. When the merger occurs, each Constellation Energy stockholder who receives shares of Exelon common stock will become a shareholder of Exelon with a percentage ownership of the combined company that will be smaller than the shareholder's percentage ownership of Constellation Energy.

        As a result, former Constellation Energy stockholders will have less voting power in the combined company than they now have with respect to Constellation Energy.

Following the merger, Constellation Energy stockholders will own equity interests in a company that owns and operates a relatively higher proportion of nuclear generating facilities, which can present unique risks.

Exelon's ownership interest in and operation of a relatively higher proportion of nuclear facilities than Constellation Energy subjects Exelon to increased associated risks, including the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials; limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives; and costs associated with regulatory oversight by the NRC, including NRC imposed fines, lost revenues as a result of any NRC ordered shutdown of Exelon nuclear facilities, or increased capital costs as a result of increased NRC safety and security regulations, including any new requirements as a result of the NRC's review of the accident at the Fukushima


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nuclear power plant in Japan. As shareholders of Exelon following the merger, Constellation Energy stockholders may be adversely affected by these risks to a greater extent than they were prior to the merger.

Item 2.    Properties

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

        BGE owns its principal headquarters building located in downtown Baltimore. BGE also leases approximately 16,640 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 NewEnergy business owns several natural gas producing properties.


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        The following table describes our generating facilities:

 
   
  At December 31, 2011    
   
Plant
  Location
  Capacity
(MW)

  %
Owned

  Capacity
Owned
(MW)

  2011
Capacity
Factor
(%) *

  Primary
Fuel

 

Calvert Cliffs Unit 1 (1)

  Calvert Co., MD     855     50.0     428     100.9  

Nuclear

Calvert Cliffs Unit 2 (1)

  Calvert Co., MD     850     50.0     425     91.7  

Nuclear

Nine Mile Point Unit 1 (1)

  Scriba, NY     628     50.0     314     84.0  

Nuclear

Nine Mile Point Unit 2 (1)

  Scriba, NY     1,141     41.0     468     95.4  

Nuclear

R.E. Ginna (1)

  Ontario, NY     581     50.0     291     84.7  

Nuclear

Brandon Shores (2)

  Anne Arundel Co., MD     1,273     100.0     1,273     52.6  

Coal

H. A. Wagner (2)

  Anne Arundel Co., MD     976     100.0     976     18.0  

Coal/Oil/Gas

C. P. Crane (2)

  Baltimore Co., MD     399     100.0     399     27.8  

Oil/Coal

Keystone

  Armstrong and Indiana Cos., PA     1,711     21.0     359 (5)   74.0  

Coal

Conemaugh

  West Moreland Co., PA     1,711     10.6     181 (5)   71.5  

Coal

Perryman

  Harford Co., MD     347     100.0     347     2.0  

Oil/Gas

Riverside

  Baltimore Co., MD     228     100.0     228     1.0  

Oil/Gas

Handsome Lake

  Rockland Twp, PA     268     100.0     268     1.9  

Gas

Notch Cliff

  Baltimore Co., MD     101     100.0     101     2.3  

Gas

Westport

  Baltimore Co., MD     116     100.0     116     0.0  

Gas

Gould Street

  Baltimore City, MD     97     100.0     97     2.5  

Gas

Philadelphia Road

  Baltimore Co., MD     61     100.0     61     0.8  

Oil

Safe Harbor

  Safe Harbor, PA     417     66.7     278     44.9  

Hydro

Criterion

  Oakland, MD     70     100.0     70     32.4  

Wind

Grande Prairie

  Alberta, Canada     93     100.0     93     20.6  

Gas

West Valley

  Salt Lake City, UT     200     100.0     200     10.3  

Gas

Hillabee Energy Center

  Alexander City, Alabama     740     100.0     740     64.3  

Gas

Colorado Bend Energy Center

  Wharton, Texas     550     100.0     550     31.6  

Gas

Quail Run Energy Center

  Odessa, Texas     550     100.0     550     14.1  

Gas

Mystic 7

  Charlestown, MA     560     100.0     560     2.0  

Oil/Gas

Mystic 8

  Charlestown, MA     703     100.0     703     75.8  

Gas

Mystic 9

  Charlestown, MA     695     100.0     695     74.8  

Gas

Fore River

  North Weymouth, MA     688     100.0     688     79.3  

Gas

Mystic Jet

  Charlestown, MA     9     100.0     9     0.1  

Oil

Panther Creek

  Nesquehoning, PA     80     50.0     40     98.0  

Waste Coal

Colver

  Colver Township, PA     102     25.0     26     99.8  

Waste Coal

Sunnyside

  Sunnyside, UT     51     50.0     26     93.6  

Waste Coal

ACE

  Trona, CA     102     31.1     32     87.5  

Coal

Jasmin

  Kern Co., CA     35     50.0     18     94.9  

Coal

POSO

  Kern Co., CA     35     50.0     18     73.6  

Coal

Rocklin

  Placer Co., CA     24     50.0     12     86.7  

Biomass

Fresno

  Fresno, CA     24     50.0     12     91.9  

Biomass

Chinese Station

  Jamestown, CA     22     45.0     10     70.7  

Biomass

Malacha

  Muck Valley, CA     32     50.0     16     37.4  

Hydro

Constellation Solar (6)

  Various     69     100.0     69      

Solar

SEGS IV

  Kramer Junction, CA     33     12.2     4     26.0  

Solar

SEGS V

  Kramer Junction, CA     24     4.2     1     37.8  

Solar

SEGS VI

  Kramer Junction, CA     34     8.8     3     28.1  

Solar

                             

Total Generating Facilities (3)(4)

        17,284           11,751          
                             
*
The capacity factors are based on installed capacity which is temperature adjusted. Therefore, it is possible to generate more than 100% of the installed capacity.
(1)
We own a 50.01% membership interest in CENG, the joint venture with EDF that holds these nuclear generating assets as a result of the sale of a 49.99% interest in CENG to EDF that was completed in November 2009. We discuss this transaction in more detail in Note 2 to Consolidated Financial Statements.
(2)
The generating facilities that we agreed to sell within six months of merger close with Exelon.
(3)
The sum of the individual plant capacity megawatts may not equal the total due to the effects of rounding.
(4)
Capacity figures represent summer seasonal claimed capacity amounts. For units with power purchase agreements, we use the contract capacity.
(5)
Reflects our proportionate interest in and entitlement to capacity from Keystone and Conemaugh, which include 2 MW of diesel capacity for Keystone and 1 MW of diesel capacity for Conemaugh.
(6)
Constellation Solar is our operation that constructs, owns, and operates solar facilities at various customer locations.

        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.

        As of December 31, 2011, 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. Mine Safety Disclosure

Not Applicable.


Executive Officers of the Registrant

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

Mayo A. Shattuck III

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

Henry B. Barron

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

James L. Connaughton

  50   Executive Vice President, Corporate Affairs, Public and Environmental Policy of Constellation Energy (since February 2009)   Chairman of the White House Council on Environmental Quality and Director of the White House Office of Environmental Policy

Paul J. Allen

  60   Senior Vice President (since January 2004) and Chief Environmental Officer (since June 2007) of Constellation Energy   None

Charles A. Berardesco

  53   Senior Vice President (since October 2008), General Counsel (since October 2008) and Corporate Secretary (since July 2004) of Constellation Energy   Vice President and Deputy General Counsel—Constellation Energy; and Associate General Counsel—Constellation Energy

Brenda L. Boultwood

  47   Senior Vice President and Chief Risk Officer of Constellation Energy (since January 2008)   Global Head of Strategy and Global Head of Derivative Services, Alternative Investment Services and Head of Treasury Services Risk Management—J.P. Morgan Chase & Company

Kenneth W. DeFontes, Jr. 

  61   Senior Vice President of Constellation Energy (since October 2004); and President and Chief Executive Officer of Baltimore Gas and Electric Company (since October 2004)   None

Andrew L. Good

  44   Senior Vice President, Corporate Strategy and Development of Constellation Energy (since November 2009)   Senior Vice President and Chief Financial Officer—Constellation Energy Resources; Senior Vice President and Chief Financial Officer—Constellation Energy Commodities Group; and Senior Vice President, Finance—Constellation Energy

Kathleen W. Hyle

  53   Senior Vice President of Constellation Energy (since September 2005); and Chief Operating Officer of Constellation Energy Resources (since November 2008)   Senior Vice President, Finance, and Chief Financial Officer—Constellation Energy Nuclear Group; Chief Financial Officer—UniStar Nuclear Energy; Senior Vice President, Finance—Constellation Energy; and Chief Financial Officer, Constellation NewEnergy

Mary L. Lauria

  47   Senior Vice President and Chief Human Resources Officer of Constellation Energy (since October 2010)   Vice President and Chief Talent Officer—Constellation Energy; Vice President, Talent Management and Leadership Development—Wyeth; and Director, Global Talent Management—Johnson & Johnson

Jonathan W. Thayer

  40   Senior Vice President and Chief Financial Officer of Constellation Energy (since October 2008)   Vice President and Managing Director, Corporate Strategy and Development—Constellation Energy; Treasurer—Constellation Energy; and Senior Vice President and Chief Financial Officer—Baltimore Gas and Electric Company

        Officers are elected by, and hold office at the will of, the Board of Directors and do not serve a "term of office" as such. There is no arrangement or understanding between any 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 31, 2012, there were 29,908 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, unless Constellation Energy elects to defer interest payments on the 8.625% Series A Junior Subordinated Debentures due June 15, 2063, and any deferred interest remains unpaid. The merger agreement with Exelon prohibits us from increasing our common stock dividend without Exelon's consent.

        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 October 2011, we announced a quarterly dividend of $0.24 per share payable April 2, 2012 to holders of record at the close of business on March 12, 2012. This is equivalent to an annual rate of $0.96 per share. If the pending merger with Exelon closes on or before March 12, 2012, the dividend will be pro-rated, with shareholders receiving $0.00264 per share per day starting December 13, 2011 and ending the day before the merger closes. In February 2012, we announced a quarterly dividend of $0.24 per share payable July 2, 2012 to holders of record at the close of business on June 11, 2012. If the pending merger with Exelon closes after March 12, 2012, but on or before June 11, 2012, the dividend will be pro-rated, with shareholders receiving $0.00264 per share per day starting March 13, 2012 and ending the day before the merger closes. In accordance with the merger agreement, a pro-rata dividend ensures that shareholders continue to receive dividends at the current rate until the closing of the merger. This pro-rata dividend, which is the daily equivalent of $0.24 per share for the full quarter, would be paid within 30 days after the closing of the pending merger with Exelon.

        Quarterly dividends were declared on our common stock during 2011 and 2010 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

 
  2011   2010  
 
   
  Price    
  Price  
 
  Dividend
Declared
  Dividend
Declared
 
 
  High   Low   High   Low  

First Quarter

  $ 0.24   $ 33.19   $ 29.70   $ 0.24   $ 36.99   $ 31.08  

Second Quarter

    0.24     38.09     30.92     0.24     38.73     32.09  

Third Quarter

    0.24     40.13     33.84     0.24     35.10     28.21  

Fourth Quarter

    0.24     40.97     35.03     0.24     33.18     27.64  
                                   

Total

  $ 0.96               $ 0.96              
                                   

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.

Period
  Total Number
of Shares
Purchased (1)
  Average Price
Paid per Share
  Total Number
of Shares
Purchased as
Part of Publicly
Announced
Plans or
Programs
  Approximate Dollar
Value of Shares
that May Yet Be
Purchased Under
the Plans and Programs
(at month end)
 

October 1 - October 31, 2011

      $          

November 1 - November 30, 2011

    104     39.52          

December 1 - December 31, 2011

    62,780     39.77          
   

Total

    62,884   $ 39.76          
   
(1)
Represents shares surrendered by employees to satisfy tax withholding obligations on vested restricted stock and restricted stock units.


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Item 6. Selected Financial Data

Constellation Energy Group, Inc. and Subsidiaries

 
  2011
  2010
  2009
  2008
  2007
 
   
 
  (In millions, except per share amounts)
 

Summary of Operations

                               

Total Revenues

  $ 13,758.2   $ 14,340.0   $ 15,598.8   $ 19,741.9   $ 21,185.1  

Total Expenses

    14,126.1     15,853.8     14,588.5     20,821.9     19,858.8  

Equity investment earnings (losses)

    19.8     25.0     (6.1 )   76.4     8.1  

Gain on U.S. Department of Energy Settlements

    93.8                  

Gain on Sale of Interest in CENG

            7,445.6          

Net Gain (Loss) on Divestitures

    57.3     245.8     (468.8 )   25.5      
   

(Loss) Income From Operations

    (197.0 )   (1,243.0 )   7,981.0     (978.1 )   1,334.4  

Gains on Sales of CEP LLC equity

                    63.3  

Other (Expense) Income

    (75.3 )   (76.7 )   (140.7 )   (69.5 )   157.4  

Fixed Charges

    265.4     277.8     350.1     349.1     292.4  
   

(Loss) Income Before Income Taxes

    (537.7 )   (1,597.5 )   7,490.2     (1,396.7 )   1,262.7  

Income Tax (Benefit) Expense

    (230.9 )   (665.7 )   2,986.8     (78.3 )   428.3  
   

(Loss) Income from Continuing Operations

    (306.8 )   (931.8 )   4,503.4     (1,318.4 )   834.4  

Loss from Discontinued Operations, Net of Income Taxes

                    (0.9 )
   

Net (Loss) Income

  $ (306.8 ) $ (931.8 ) $ 4,503.4   $ (1,318.4 ) $ 833.5  

Net Loss (Income) Attributable to Noncontrolling Interests and BGE Preference Stock Dividends

    33.5     50.8     60.0     (4.0 )   12.0  
   

Net (Loss) Income Attributable to Common Stock

  $ (340.3 ) $ (982.6 ) $ 4,443.4   $ (1,314.4 ) $ 821.5  
   

(Loss) Earnings Per Common Share from Continuing Operations Assuming Dilution

  $ (1.70 ) $ (4.90 ) $ 22.19   $ (7.34 ) $ 4.51  

Loss from Discontinued Operations

                    (0.01 )
   

(Loss) Earnings Per Common Share Assuming Dilution

  $ (1.70 ) $ (4.90 ) $ 22.19   $ (7.34 ) $ 4.50  
   

Dividends Declared Per Common Share

  $ 0.96   $ 0.96   $ 0.96   $ 1.91   $ 1.74  
   

Summary of Financial Condition

                               

Total Assets

  $ 19,412.6   $ 20,018.5   $ 23,544.4   $ 22,284.1   $ 21,742.3  
   

Current Portion of Long-Term Debt

  $ 174.9   $ 305.3   $ 56.9   $ 2,591.5   $ 380.6  
   

Capitalization:

                               

Long-Term Debt

  $ 4,844.8   $ 4,448.8   $ 4,814.0   $ 5,098.7   $ 4,660.5  

Noncontrolling Interests

    116.9     88.8     75.3     20.1     19.2  

BGE Preference Stock Not Subject to Mandatory Redemption

    190.0     190.0     190.0     190.0     190.0  

Common Shareholders' Equity

    7,093.9     7,829.2     8,697.1     3,181.4     5,340.2  
   

Total Capitalization

  $ 12,245.6   $ 12,556.8   $ 13,776.4   $ 8,490.2   $ 10,209.9  
   

Financial Statistics at Year End

                               

Ratio of Earnings to Fixed Charges

    N/A     N/A     14.76     N/A     3.84  

Book Value Per Share of Common Stock

  $ 35.17   $ 39.19   $ 43.27   $ 15.98   $ 29.93  

N/A—Calculation is not applicable as a result of the net losses for 2011, 2010 and 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

 
  2011
  2010
  2009
  2008
  2007
 
   
 
  (In millions)
 

Summary of Operations

                               

Total Revenues

  $ 2,993.1   $ 3,461.7   $ 3,579.0   $ 3,703.7   $ 3,418.5  

Total Expenses

    2,678.3     3,107.5     3,310.6     3,521.2     3,084.2  
   

Income From Operations

    314.8     354.2     268.4     182.5     334.3  

Other Income

    21.0     20.8     25.4     29.6     26.9  

Fixed Charges

    126.6     130.3     139.3     139.9     125.3  
   

Income Before Income Taxes

    209.2     244.7     154.5     72.2     235.9  

Income Taxes

    73.5     97.1     63.8     20.7     96.0  
   

Net Income

    135.7     147.6     90.7     51.5     139.9  

Preference Stock Dividends

    13.2     13.2     13.2     13.2     13.2  
   

Net Income Attributable to Common Stock before Noncontrolling Interests

  $ 122.5   $ 134.4   $ 77.5   $ 38.3   $ 126.7  

Net Loss (Income) Attributable to Noncontrolling Interests

            7.3         (0.1 )
   

Net Income Attributable to Common Stock

  $ 122.5   $ 134.4   $ 84.8   $ 38.3   $ 126.6  
   

Summary of Financial Condition

                               

Total Assets

  $ 6,987.0   $ 6,667.3   $ 6,453.1   $ 6,086.2   $ 5,783.0  
   

Current Portion of Long-Term Debt

  $ 172.5   $ 81.7   $ 56.5   $ 90.0   $ 375.0  
   

Capitalization

                               

Long-Term Debt

  $ 2,185.9   $ 2,059.9   $ 2,141.4   $ 2,197.7   $ 1,862.5  

Noncontrolling Interest

            17.6     16.9     16.8  

Preference Stock Not Subject to Mandatory Redemption

    190.0     190.0     190.0     190.0     190.0  

Common Shareholder's Equity

    2,110.7     2,073.2     1,938.8     1,538.2     1,671.7  
   

Total Capitalization

  $ 4,486.6   $ 4,323.1   $ 4,287.8   $ 3,942.8   $ 3,741.0  
   

Financial Statistics at Year End

                               

Ratio of Earnings to Fixed Charges

    2.56     2.80     2.07     1.50     2.84  

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

    2.22     2.41     1.80     1.33     2.42  

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 organized around three business segments: a generation business (Generation), a customer supply business (NewEnergy), 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 2011, 2010, and 2009. 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

Our strategy is to provide innovative and risk-mitigating energy products and solutions to North American wholesale and retail customers. Overall, we strive to serve our customers with diverse products and solutions to meet their energy needs.

        In executing this strategy, we leverage our core strengths of:

    maintaining and growing strong and diverse supply relationships with retail and wholesale customers,
    owning, developing, operating, and contracting for generation assets,
    integrating our expertise in managing physical and financial risks, and
    providing reliable, regulated utility service to customers.

        Our NewEnergy business focuses on sales of electricity, natural gas, and related products and solutions to various customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental, and residential customers in competitive markets. The retail NewEnergy customer supply operation combines a unified sales force with a customer-centric model that leverages technology to broaden the range of products and solutions we offer, which we believe promotes stronger customer relationships. This model focuses on efficiency and cost reduction, which we believe will provide a platform that is scalable and able to capitalize on opportunities for future growth.

        NewEnergy obtains energy from both owned and contracted supply resources and actively manages these physical and contractual assets in order to derive incremental value. Additionally, NewEnergy is involved in the development, exploration, exploitation, and harvesting of natural gas properties.

        Our Generation business has a fleet of plants that is strategically located in markets that support our customer-facing business and includes various fuel types, such as coal, natural gas, oil, nuclear, and renewable sources. We generally have load obligations greater than our generation output. Going forward, we intend to invest in generation assets in the markets where we serve load to provide a more efficient and balanced profile between our generation production and our customer load obligations. One of the expected benefits of our merger with Exelon is the combination of Exelon's large, environmentally advantaged generation fleet and our customer-facing business. This combination is expected to create a platform for growth and enhance our ability to service our load obligations with this generation output, thus reducing our costs.

        Our strategy is enabled by a fleet of generation facilities and our risk management capabilities. This combination of our Generation and NewEnergy businesses also allows us to operate in a manner so we can minimize our collateral requirements. We discuss our collateral requirements in the Collateral section.

        BGE, our regulated utility located in central Maryland, provides standard offer service and distributes electricity and gas to customers. BGE is also focusing on enhancing reliability and customer satisfaction, and is implementing customer demand response initiatives, including a comprehensive smart grid initiative and a full portfolio of conservation programs.


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        The ability of energy consumers to choose their supplier, regulatory change, and energy market conditions significantly impact our business. In response, we regularly evaluate our strategies to improve our competitive position. We actively anticipate and adapt to the business environment and regulatory changes that impact our industry. We are committed to maintaining a strong balance sheet and investment-grade credit quality by making disciplined investment and capital management decisions to support our strategic initiatives in an efficient and effective manner.


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.

        In 2009, 2010, and 2011 markets in which we operate were affected by declining prices for power, gas, and capacity. We discuss the impact of declining commodity prices on our future earnings in more detail in the Generation Results section.

        Competition also impacts our business. We discuss competition in more detail in Item 1. Business—Competition section.

        The impacts of electric competition 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 competition, which we discuss in Item 1. Business—Baltimore Gas and Electric Company—Electric 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 shown on customer billings as 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.

New Electric Generation

In September 2011, the Maryland PSC issued a notice requiring regulated electric distribution companies to issue a request for proposals for the construction of new electric generation. Under the proposal, the electric distribution companies would enter into long-term contract-for-difference arrangements, under which the electric distribution companies would pay a fixed contract price in exchange for the variable market price. The requests for proposals were issued by electric distribution companies, including BGE, in October 2011 with initial proposals due January 20, 2012. The Maryland PSC held a hearing in January 2012 to determine whether new generation is needed to meet the long-term, anticipated demand in Maryland and, if so, the amount of generation that is needed. Following the determination of the need for new generation, the Maryland PSC will select and approve the winning offers by the second quarter of 2012. The Maryland PSC established this schedule in order to preserve a possible offering of new generation capacity in the May 2012 PJM capacity auction for the 2015 - 2016 delivery years. Depending on the outcome of this process, a requirement that BGE enter into such long-term arrangements could have a material effect on our, or BGE's, financial results.

Purchase of Supplier Receivables

Effective July 15, 2010, BGE, pursuant to Maryland PSC requirements, began to purchase receivables at a discount from third party competitive energy suppliers that provide our customers electricity and/or gas. The discount rate applied to the receivables is a regulated rate which is intended to cover BGE's costs associated with purchasing these receivables, such as uncollectibles, and is subject to an annual true-up to reflect actual costs.

Base Rates

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

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

        On December 6, 2010, the Maryland PSC issued an abbreviated order authorizing BGE to increase electric distribution rates by no more than $31.0 million and increase gas distribution rates by no more than $9.8 million for service rendered on or after December 4, 2010. The electric distribution rate increase was based upon an 8.06% rate of return with a 9.86% return on equity and a 52% equity ratio. The gas distribution rate increase was based upon a 7.90% rate of return with a 9.56% return on equity and a 52% equity ratio. In March 2011, the Maryland PSC issued a comprehensive rate order setting forth the details of the decision contained in its abbreviated electric and gas distribution rate order issued in December 2010.

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


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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 (except as discussed below with respect to major storms) 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.

        In January 2012, the Maryland PSC issued an order prospectively prohibiting Maryland electric utilities with a revenue decoupling mechanism from collecting a certain portion of decoupling revenue during major storm events if customer service is not restored within a specified period of time. We do not expect the impact of this prohibition to have a material effect on our, or BGE's, financial results.

Demand Response and Advanced Metering Programs

BGE defers costs associated with its demand response programs as a regulatory asset and recovers these costs from customers in future periods.

        In August 2010, the Maryland PSC approved a comprehensive smart grid initiative for BGE which includes the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of approximately $480 million. The Maryland PSC's approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is delivered to customers. Under a grant from the United States Department of Energy (DOE) BGE is a recipient of $200 million in federal funding for its smart grid and other related initiatives. This grant allows BGE to be reimbursed for smart grid and other expenditures up to $200 million, substantially reducing the total cost of these initiatives. As of December 31, 2011, we have received $95.3 million of the $200 million grant from the DOE.

        We discuss BGE's electric load management programs in more detail in Item 1. Business—Baltimore Gas and Electric Company—Electric Load Management. We discuss the associated regulatory assets in Note 6 to Consolidated Financial Statements.

Electric 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. However, BGE is required to provide all residential electric customers a credit for the residential return component of the administrative fee. This credit will be given to customers through December 31, 2016. Currently, BGE is involved in a Maryland PSC proceeding to determine the future, on-going structure of the SOS administrative fee charged to all SOS customers.

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 section and in Note 6 to Consolidated Financial Statements.

Potential Reliability and Quality of Service Standards

During its 2011 legislative session, the Maryland General Assembly passed legislation:

    directing the Maryland PSC to enact service quality and reliability regulations by July 1, 2012 relating to the delivery of electricity to retail electric customers,
    increasing existing penalties for failure to meet these and other Maryland PSC regulations, and
    directing the Maryland PSC to undertake certain studies addressing utility liability for certain customer damages, electric utility service restoration plans, and modifications to existing revenue decoupling mechanisms for extended service interruptions.

        In May 2011, the Governor signed this legislation into law and the Maryland PSC has instituted a rulemaking proceeding to draft the required service quality and reliability regulations. Once the regulations are enacted, the costs incurred by BGE to comply with them will affect our, and BGE's, financial results.

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.

        In addition to PJM, RTOs exist in other regions of the country such as the Midwest, New York, Texas, 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 Generation and NewEnergy businesses participate 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


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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. In May 2010, FERC issued an order approving in part and reversing in part the ALJ decision. The FERC order results in additional SECA liabilities being imposed on us. In June 2010, we filed requests for rehearing of the FERC order on the ALJ decision, as did other interested parties. In July 2010, BGE filed a petition for review of FERC's approval of the SECA methodology. In the interim, PJM and MISO have made filings at FERC to comply with the May 2010 decision and to impose charges accordingly. In October 2011, FERC denied our requests for rehearing of its May 2010 decision. In November 2011, we filed petitions for review of that decision in the U.S. Court of Appeals for the District of Columbia Circuit. The District of Columbia Circuit consolidated the BGE petitions, our petition, and the petitions of other parties in the SECA proceeding. 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 requested 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. FERC dismissed the complaint and denied rehearing, and ultimately the Maryland PSC and New Jersey Board of Public Utilities appealed the case to the United States Court of Appeals for the District of Columbia. In February 2011, the court denied the petition for review and held that FERC adequately explained why the RPM auction structure was just and reasonable. The petitioners did not appeal the court's decision to the United States Supreme Court and therefore FERC's decision in our favor is final and non-appealable.

        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 previously wholly owned 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 actively participated in the proceeding, and in September 2010 the ALJ issued an Initial Decision finding that the Connecticut Parties failed to prove their case and dismissed the complaint against CCG. The Initial Decision was approved by FERC and FERC denied a rehearing of the Connecticut Parties in January 2012. The Connecticut Parties have 60 days to seek a petition


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of the FERC ruling in a Circuit Court of Appeals of the United States.

        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.

        In addition to legal challenges to capacity markets and regulatory advocacy before FERC seeking to revise the capacity market structures, states are seeking more direct ways to affect the results of wholesale capacity markets. In January 2011, the New Jersey legislature adopted legislation that would provide for guaranteed cost recovery for the development of up to 2,000 MWs of new base load or mid-merit generation in exchange for the requirement that the new generation clear in the PJM capacity market. Similarly, the Maryland PSC issued a draft Request for Proposals that, subject to an evidentiary hearing confirming the reliability need for such resources, contemplates having Maryland ratepayers fund the development of new generation and to require that eligible new generation clear in the PJM capacity market. Such state efforts are intended to depress capacity prices, and are subject to legal and regulatory challenge. Depending on the outcome of these challenges, these state efforts 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.

        Concerns over the security of the country's energy infrastructure could lead to additional 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.

Financial Regulatory Reform

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted in July 2010. While the Dodd-Frank Act is focused primarily on the regulation and oversight of financial institutions, it also provides for a new regulatory regime for derivatives, including mandatory clearing of certain swaps, exchange trading, margin requirements, and other transparency requirements. The Dodd-Frank Act, however, also preserves the ability of end users in our industry to hedge their risks, which we believe results in the new derivatives requirements not being applicable to us for most of our activities. However, there will be several key rulemakings to implement the derivatives requirements, which, depending on the final scope of the regulations, could attempt to impose significant obligations on us nonetheless. Final regulations may address collateral requirements and exchange margin cash postings, which if applicable to us despite being an end user of derivatives, could have the effect of increasing collateral requirements or the amount of exchange margin cash postings in lieu of letters of credit currently issued on over-the-counter contracts. These regulations could also result in additional transactional and compliance costs to the extent they apply to us, and could impact market liquidity.

        In addition to new regulation over derivatives, the Dodd-Frank Act amends the Sarbanes-Oxley Act to permanently exempt nonaccelerated filers, including BGE, from the requirement to obtain an audit report on internal controls over financial reporting.

Market Oversight

Regulatory agencies that have jurisdiction over our businesses, including the FERC and the Commodity Future Trading Commission (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

Generation and NewEnergy Businesses

Weather conditions in the different regions of North America influence the financial results of our Generation and NewEnergy businesses. 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


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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—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 NewEnergy 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,
    international supply and demand, and
    general economic conditions.

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

    weather conditions,
    market liquidity,
    capability and reliability of the physical electricity and gas systems,
    state and local environmental regulations,
    local transportation systems, and
    the nature and extent of electricity competition.

        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 accounting policies discussed below 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 primarily to manage commodity price risk as well as interest rate 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 the scope of these requirements, 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


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    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, future changes in accounting requirements 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 or if they contain embedded 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 treatment, 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

There are several permissible accounting treatments for derivatives. 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 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:

 
  Recognition and Measurement
Accounting Treatment
  Balance Sheet
  Income Statement
 
Mark-to-market   •  Derivative asset or liability recorded at fair value   •  Changes in fair value recognized in earnings
 
Cash flow hedge   •  Derivative asset or liability recorded at fair value
•  Effective changes in fair value recognized in accumulated other comprehensive income
  •  Ineffective changes in fair value recognized in earnings

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

•  Book value of hedged asset or liability adjusted for changes in its fair valuec
  •  Changes in fair value recognized in earnings

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

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

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

        We exercise judgment in determining which derivatives qualify for a particular accounting treatment, 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 on a net basis.


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        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 NPNS accrual or hedge accounting for our physical energy delivery activities because accrual accounting more closely aligns the timing of earnings recognition, cash flows, and the underlying business activities. We apply mark-to-market accounting for certain risk management and trading activities as follows:

    our competitive retail gas customer supply activities and, for new transactions closed since June 30, 2010, our fixed quantity competitive retail power 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,
    economic hedges of other contracts that require mark-to-market accounting treatment to ensure symmetrical accounting treatment,
    economic hedges of activities that require accrual accounting,
    interest rate swaps related to our debt if we do not elect hedge accounting, and
    trading activities.

        As a result of making these judgments, the selection of accounting treatment 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:

 
  Accounting Treatment
Effect of Changes
in Fair Value on:

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

•  Decrease or increase in hedged asset or liability

  •  No impact
 
AOCI   •  No impact   •  Increase or decrease for effective portion of hedge   •  No impact   •  No impact
 
Earnings prior to settlement   •  Increase or decrease   •  Increase or decrease for ineffective portion of hedge   •  Increase or decrease for change in derivatives

•  Decrease or increase for change in hedged asset or liability

•  Increase or decrease for ineffective portion

  •  No impact
 
Earnings at settlement   •  No impact   •  Amounts in AOCI reclassified to earnings when hedged forecasted transaction affects earnings or when the forecasted transaction becomes probable of not occurring   •  Hedged margin recognized in earnings   •  Revenue or expense recognized in earnings when underlying physical commodity is sold or consumed
 

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


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

Impacts of Uncertainty

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

    uncertainty surrounding inputs to the estimates of fair value 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, real estate, and unamortized energy contracts) 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,
    negative credit events of a counterparty,
    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.

Unproved 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


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allowance. The determination of whether to continue to develop the lease is based upon the economics (forward prices and the level of gas reserves) associated with extracting the estimated gas reserves, which necessarily involves the exercise of judgment.

Investments

We evaluate our equity method and cost method investments, including our 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.

        We continuously monitor issues that potentially could impact future profitability of our equity method investments that own coal, hydroelectric, fuel processing projects, as well as our equity investment in our nuclear joint venture. These issues include environmental and legislative initiatives. We discuss certain risks and uncertainties in more detail in our Forward Looking Statements and Item 1A. Risk Factors sections. However, should future events cause these investments to become uneconomic, our investments in these projects could become impaired.

        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 renewable energy projects could become impaired, and any losses recognized could be material.

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

Pending Merger with Exelon Corporation

On April 28, 2011, we entered into an Agreement and Plan of Merger with Exelon Corporation (Exelon). At closing, each issued and outstanding share of common stock of Constellation Energy will be cancelled and converted into the right to receive 0.93 shares of common stock of Exelon, and Constellation Energy will become a wholly owned subsidiary of Exelon.

        Prior to the completion of the merger, which is subject to various approvals, Constellation Energy will continue to operate as a separate company. The following discussion and analysis of our results of operations and financial condition relates solely to Constellation Energy and its subsidiaries.

        We discuss this transaction and the costs incurred to date in more detail in Note 2 to Consolidated Financial Statements.

Acquisitions

Haynesville Shale Gas Property

In December 2011, we acquired natural gas working interests and net revenue interests in certain producing wells and certain proved developed wells and proved undeveloped locations in Louisiana for a total of approximately $58.2 million. We discuss this transaction in more detail in Note 15 to Consolidated Financial Statements.

ONEOK Energy Marketing Company

In February 2012, we acquired all of the outstanding stock of ONEOK Energy Marketing Company, a retail natural gas marketing company, for approximately $22.5 million, subject to a working capital adjustment. We discuss this transaction in more detail in Note 15 to Consolidated Financial Statements.

MXenergy Holdings Inc.

In July 2011, we acquired all of the outstanding stock of MXenergy Holdings Inc. (MXenergy), a retail energy marketer of natural gas and electricity to residential and commercial customers in competitive markets in the United States and Canada for approximately $218.7 million in cash. We discuss this transaction in more detail in Note 15 to Consolidated Financial Statements.

Star Electricity, Inc.

In May 2011, we acquired all of the outstanding stock of Star Electricity, Inc. (StarTex), a retail electric provider, for approximately $160.4 million in cash. We discuss this transaction in more detail in Note 15 to Consolidated Financial Statements.

Boston Generating

In January 2011, we completed the acquisition of Boston Generating's 2,950 MW fleet of generating plants for approximately $1.1 billion in cash. We discuss this transaction in more detail in Note 15 to Consolidated Financial Statements.

Divestitures

Upstream Gas Property

In December 2011, we sold all of our interests in a subsidiary that owned natural gas assets in the south Texas region for $93.0 million. We recognized a $23.0 million pre-tax gain. We


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discuss this transaction in Note 2 to Consolidated Financial Statements.

Constellation Energy Partners LLC

In August 2011, we sold a majority of our equity interests in Constellation Energy Partners LLC (CEP) to PostRock Energy Corporation (PostRock) for cash, shares of PostRock common stock and warrants to buy additional shares of PostRock common stock. In December 2011, we sold additional equity interests in CEP to PostRock for cash. We discuss these transactions in more detail in Note 2 to Consolidated Financial Statements.

Quail Run Energy Center

In June 2011, we terminated the agreement to sell our Quail Run Energy Center (Quail Run), a 550 MW natural gas plant in west Texas, to High Plains Diversified Energy Corporation. We had previously entered into the agreement to sell Quail Run in December 2010. We discuss this development in Note 2 to Consolidated Financial Statements.

Commodity Prices

During 2011, the energy markets were affected by large fluctuations in both forward and spot commodity prices. The changes in spot prices from January 1, 2011 through December 31, 2011 were as follows:

    power prices declined approximately 21%, and
    gas prices declined by approximately 32%.

        These changes in commodity prices contributed to significant mark-to-market losses, resulted in impairment charges, and, therefore, materially impacted our results. We discuss these changes in the Results of Operations section.

Gains on Settlements with U.S. Department of Energy (DOE)

During 2011, we recognized the following pre-tax gains related to agreements with the DOE that settled lawsuits to recover damages for costs incurred through November 6, 2009 caused by the DOE's failure to comply with legal and contractual obligations to dispose of spent nuclear fuel at these nuclear plants:

    $39.4 million related to the Calvert Cliffs nuclear power plant, and
    $54.4 million related to the Ginna nuclear power plant.

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

Financings

BGE Issuance of Notes

In November 2011, BGE issued $300 million of 3.50% Notes due November 15, 2021. We discuss this financing transaction in more detail in Note 9 to Consolidated Financial Statements.

Secured Solar Credit Lending Agreement

In July 2011, a subsidiary of Constellation Energy entered into a three year senior secured credit facility associated with certain solar projects that we own. The amount committed under the facility is $150 million. We discuss this lending agreement in more detail in Note 9 to Consolidated Financial Statements.

Amended Reserve-Based Facility for Upstream Gas Operations

In July 2011, we amended and extended our existing reserve based lending facility that supports our upstream gas operations. The borrowing base committed under the facility was increased to $150 million. We discuss this agreement in more detail in Note 9 to Consolidated Financial Statements.

Sacramento Solar Project Facility

In July 2011, a subsidiary of Constellation Energy entered into a $40.7 million nonrecourse project financing to fund construction of our 30MW solar facility in Sacramento, California. The construction borrowings will convert into a 19-year variable rate note upon commercial operation of the facility. We discuss this financing in more detail in Note 9 to Consolidated Financial Statements.

Revolving Promissory Note with CENG

In May 2011, CENG issued an unsecured revolving promissory note to borrow up to an aggregate principal amount of $62.5 million from a subsidiary of Constellation Energy. We discuss this related party financing in Note 16 to Consolidated Financial Statements.

Third Quarter 2011 Texas Weather Event

In the third quarter of 2011, the Texas region incurred extreme high temperatures for a prolonged period of time. This heat wave was compounded by fossil generator outages and a lack of wind plant availability throughout the region, which led to price spikes well above historical averages for replacement power that we had to purchase. This negatively affected our NewEnergy operating results by approximately $33 million after-tax. We discuss the impact of this development on our overall results in the NewEnergy operating results section.

Hurricane Irene

In August 2011, Hurricane Irene caused extensive damage to BGE's electric distribution system and created power outages that lasted several days. BGE incurred total costs currently estimated to be $79.7 million, which includes capital costs of $29.6 million and maintenance expenses of $50.1 million pre-tax, or $29.9 million after-tax, in 2011 to repair its distribution system and restore service to customers. The maintenance expenses included $41.1 million pre-tax, or $24.6 million after-tax, of estimated incremental expenses. We discuss the impact of Hurricane Irene on our Regulated Electric Business operating results section.


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Results of Operations

In this section, we discuss our earnings and the factors affecting them. We begin with a general overview, and then separately discuss earnings for our operating segments. Significant changes in other (expense) income, 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 2011, 2010 and 2009 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 2011, 2010 and 2009 results to prior periods and will alter Constellation Energy's operating results in the future. In this section, we highlight the 2011, 2010 and 2009 impacts of these items.

Overview

Results

 
  2011
  2010
  2009
 
   
 
  (In millions, after-tax)
 

Net (Loss) Income:

                   

Generation

  $ (441.1 ) $ (1,255.3 ) $ 4,766.7  

NewEnergy

    2.8     176.2     (348.2 )

Regulated electric

    93.6     110.0     79.1  

Regulated gas

    42.1     37.6     25.5  

Other nonregulated

    (4.2 )   (0.3 )   (19.7 )
   

Net (Loss) Income

  $ (306.8 ) $ (931.8 ) $ 4,503.4  
   

Net (Loss) Income attributable to common stock

  $ (340.3 ) $ (982.6 ) $ 4,443.4  
   

Change from prior year

  $ 642.3   $ (5,426.0 )      
   

        Our total net loss attributable to common stock for 2011 decreased compared to 2010 by $642.3 million, or $3.20 per share, mostly because of the following:

 
  Increase/(Decrease)
2011 vs. 2010

 
   
(In millions, after-tax)
 

Generation gross margin

  $ 81  

Increases in Generation non-gross margin expenses related to:

       

Acquisition of Boston Generating fleet of generating assets in January 2011

    (81 )

NewEnergy gross margin

    (116 )

NewEnergy hedge ineffectiveness

    (24 )

NewEnergy third quarter 2011 Texas region weather event

    (33 )

NewEnergy gain on divestitures

    34  

NewEnergy contract assignments / origination

    25  

Regulated businesses

    27  

Other nonregulated businesses

    (9 )

Total change in Other Items Included in Operations per table below

    797  

All other changes

    (59 )
   

Total Change

  $ 642  
   

        Our total net (loss) income attributable to common stock for 2010 decreased compared to 2009 by $5.4 billion, or $27.09 per share, mostly because of the following:

 
  Increase/(Decrease)
2010 vs. 2009

 
   
(In millions, after-tax)
 

Generation gross margin, primarily due to the deconsolidation of CENG

  $ (682 )

Lower Generation operating expenses, primarily labor and benefit costs due to the deconsolidation of CENG

    390  

Lower Generation accretion expense of asset retirement obligations due to deconsolidation of CENG

    37  

Lower Generation taxes other than income taxes due to deconsolidation of CENG

    27  

Lower Generation depreciation and amortization due to deconsolidation of CENG

    28  

NewEnergy gross margin

    78  

NewEnergy hedge ineffectiveness

    (55 )

Loss on NewEnergy international coal contract assignments

    (25 )

Regulated businesses

    (21 )

Other nonregulated businesses

    5  

Total change in Other Items Included in Operations per table below

    (5,375 )

All other changes

    167  
   

Total Change

  $ (5,426 )
   


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Other Items Included in Operations (after-tax):

 
  2011
  2010
  2009
 
   
 
  (In millions, after-tax)
 

Impairment losses and other costs

  $ (530.2 ) $ (1,487.1 ) $ (96.2 )

Impact of power purchase agreement with CENG (1)

    (118.5 )   (113.3 )    

Amortization of basis difference in CENG

    (90.5 )   (117.5 )   (17.8 )

Hurricane Irene incremental storm expenses

    (24.6 )        

Merger costs

    (70.9 )       (13.8 )

Gain on settlements with DOE

    57.3          

Transaction fees for Boston Generating acquisition

    (9.9 )        

Gain on Comprehensive Agreement with EDF

        121.3      

International coal contract dispute settlement

          35.4      

Loss on early retirement of 2012 Notes

        (30.9 )    

Gain on sale of interest in Mammoth Lakes geothermal generating facility

        24.7      

Credit facility amendment/termination fees

    (5.8 )   (13.6 )   (37.7 )

Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits

        (8.8 )    

Gain on sale of 49.99% interest in CENG

            4,456.1  

International commodities operation and gas trading operation (2)

            (371.9 )

BGE residential customer rate credit

            (67.1 )

Impairment of nuclear decommissioning trust assets

            (46.8 )

Loss on redemption of Zero Coupon Senior Notes

            (10.0 )

Workforce reduction costs

            (9.3 )
   

Total Other Items

  $ (793.1 ) $ (1,589.8 ) $ 3,785.5  
   

Change from prior year

  $ 796.7   $ (5,375.3 )      
   
(1)
The net impact to the Company of the power purchase agreement with CENG was $200.4 million pre-tax for 2011 and $185.6 million pre-tax for 2010. This amount represents the amortization of our $0.8 billion "Unamortized energy contract asset" less our 50.01% equity in CENG's amortization of its $0.8 billion "Unamortized energy contract liability."

(2)
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 were 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 for 2009 also include amounts related to the operations we divested.

Generation Business

Background

Our Generation business is discussed in detail in Item 1. Business—Operating Segments section.

        We have presented the results of this business reflecting that we have hedged 100% of generation output and fuel for generation. This is based on executing hedges at prevailing market prices with the NewEnergy business. Taking into account previously executed hedges at the end of each fiscal year, we ensure that the Generation business is fully hedged by the NewEnergy business for the next year. Therefore, all commodity price risk is managed by and presented in the results of our NewEnergy business as discussed below. Generally, changes in the results of our Generation business during the period are due to changes in the availability of the generating assets.

        During 2011, power prices continued to decline, reflecting economic conditions and projected increases in natural gas supplies. However, prices for coal have not declined to the same extent as power prices. The relationship between power and fuel prices directly affects the earnings of our Generation business. Although our NewEnergy business hedges portions of our future power sales and fuel purchases, the amounts we have hedged are higher for the near term and decline over time. We have already locked in prices for our expected generation output for 2012. However, consistent with our hedging approach, we have only hedged a portion of the expected output for 2013, and those hedges are at lower prices. If the current power and fuel price environment continues, we anticipate that our Generation business will have lower earnings in future years, especially in 2012.

        Additionally, we evaluated our generating plants and our investments in electric generation facilities for impairment as a result of power price declines in 2011. We recorded an impairment charge in 2011 for our investments in electric generation facilities and our investment in CENG, but none of our wholly owned generating plants were impaired. However, further decreases in power prices could result in estimated future cash flows declining below the carrying value of our plants, which would require us to record an impairment charge on our generating plants. We discuss our impairment charges in Note 2 to Consolidated Financial Statements.


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Results

 
  2011
  2010
  2009
 
   
 
  (In millions)
 

Revenues

  $ 2,717.7   $ 2,244.3   $ 2,774.2  

Fuel and purchased energy expenses

    (1,766.8 )   (1,444.8 )   (692.0 )
   

Gross margin

    950.9     799.5     2,082.2  

Operating expenses

    (468.7 )   (379.7 )   (1,008.4 )

Impairment losses and other costs

    (891.0 )   (2,476.7 )    

Merger costs

    (61.2 )       (101.8 )

Depreciation, depletion, accretion, and amortization

    (187.4 )   (137.7 )   (238.9 )

Taxes other than income taxes

    (45.1 )   (23.6 )   (67.4 )

Equity investment earnings (losses):

                   

CENG

    (4.3 )   23.6     4.3  

UNE

        (16.8 )   (24.7 )

Other

    24.1     18.2     20.6  

Gain on settlement with DOE

    93.8          

Net gain on divestitures

        242.9     7,445.6  
   

(Loss) Income from Operations

  $ (588.9 ) $ (1,950.3 ) $ 8,111.5  
   

Net (Loss) Income

  $ (441.1 ) $ (1,255.3 ) $ 4,766.7  
   

Net (Loss) Income attributable to common stock

  $ (441.1 ) $ (1,255.3 ) $ 4,766.7  
   

Change from prior year

  $ 814.2   $ (6,022.0 )      
   

Other Items Included in Operations (after-tax):

                   

Impairment losses and other costs

  $ (530.2 ) $ (1,487.1 ) $  

Impact of power purchase agreement with CENG (1)

    (118.5 )   (113.3 )    

Amortization of basis difference in CENG

    (90.5 )   (117.5 )   (17.8 )

Gain on settlements with DOE

    57.3          

Merger costs

    (37.0 )       (9.7 )

Transaction fees for Boston Generating acquisition

    (9.9 )        

Gain on Comprehensive Agreement with EDF

        121.3      

Loss on early retirement of 2012 Notes

        (30.9 )    

Gain on sale of Mammoth Lakes geothermal generating facility

        24.7      

Credit facility amendment/termination fees

        (9.0 )   (13.7 )

Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits

        (0.8 )    

Gain on sale of 49.99% interest in CENG

            4.456.1  

Impairment of nuclear decommissioning trust assets

            (46.8 )

Loss on redemption of Zero Coupon Senior Notes

            (10.0 )
   

Total Other Items

  $ (728.8 ) $ (1,612.6 ) $ 4,358.1  
   

Change from prior year

  $ 883.8   $ (5,970.7 )      
   

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)
The net impact to the Company of the power purchase agreement with CENG was $200.4 million pre-tax for 2011 and $185.6 million pre-tax for 2010. This amount represents the amortization of our $0.8 billion "Unamortized energy contract asset" less our 50.01% equity in CENG's amortization of its $0.8 billion "Unamortized energy contract liability."

Effects of 2009 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, beginning November 6, 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. This change in accounting treatment affected the comparability of Generation's results between 2010 and 2009. We discuss our transaction with EDF in more detail in Note 2 to Consolidated Financial Statements.

Revenues

Our Generation revenues increased $473.4 million in 2011 compared to 2010 and decreased $529.9 million in 2010 compared to 2009 primarily due to the following:

 
  2011
vs. 2010

  2010
vs. 2009

 
   
 
  (In millions)
 

Decrease in volume of output primarily due to the deconsolidation of CENG nuclear generating assets

  $   $ (690 )

Increase in volume of output primarily due to the acquisition of the Boston Generating fleet of generating assets in January 2011, additional volume due to the beginning of commercial dispatch of the Hillabee Energy Center and the acquisition of the Texas combined cycle generation facilities in 2010

    648     198  

Increase (decrease) in volume of output due to reduced (higher) impact of outages at our fossil plants

    38     (127 )

(Decrease) increase in contracted power prices

    (227 )   116  

All other

    14     (27 )
   

Total increase (decrease) in Generation revenues

  $ 473   $ (530 )
   

Fuel and Purchased Energy Expenses

Our Generation fuel and purchased energy expenses increased $322.0 million in 2011 compared to 2010 and increased $752.8 million in 2010 compared to 2009 primarily due to the following:

 
  2011
vs. 2010

  2010
vs. 2009

 
   
 
  (In millions)
 

Increase in purchased energy costs due to power purchase agreement with CENG compared with nuclear fuel costs

  $   $ 741  

Increase in volume of gas consumed due to the acquisition of the Boston Generating fleet of generating assets in January 2011

    218      

Increase (decrease) due to reduced (higher) impact of outages at our fossil plants

    2     (87 )

Increase in fuel costs primarily related to higher contract prices to operate our generating assets

    56     59  

All other

    46     40  
   

Total increase in Generation fuel and purchased energy expenses

  $ 322   $ 753  
   


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Operating Expenses

Our Generation business operating expenses increased $89.0 million during 2011 as compared to 2010 primarily due to the costs associated with the acquisition of the Boston Generating fleet of generating assets in January 2011.

        Our Generation business operating expenses decreased $628.7 million during 2010 as compared to 2009 due to lower labor and benefit costs of $499.9 million and lower non-labor operating expenses of $128.8 million, the majority of which results from the absence of costs in 2010 due to the deconsolidation of CENG.

Impairment Losses and Other Costs

We discuss our impairment charges in more detail in Note 2 to Consolidated Financial Statements.

Merger Costs

We discuss costs related to the proposed merger with Exelon in more detail in Note 2 to Consolidated Financial Statements.

Depreciation, Depletion, Accretion, and Amortization Expense

Our Generation business incurred higher depreciation, depletion, accretion, and amortization expenses of $49.7 million during 2011 compared to 2010 primarily due to additional depreciation of:

    $33.8 million on the Boston Generating facilities acquired in January 2011,
    $5.2 million related to a sub-bituminous safety system and coal conveyor that was placed in service in 2011 at one of our coal generating facilities, and
    $6.7 million related to the June 2010 commencement of operations at our Hillabee Energy Center.

        Our Generation business incurred lower depreciation, depletion, accretion, and amortization expenses of $101.2 million during 2010 compared to 2009 due to a decrease of $94.0 million in depreciation on the nuclear generating facilities and a decrease of $60.5 million in accretion on asset retirement obligations, both resulting from the deconsolidation of CENG on November 6, 2009. These decreases were partially offset by an increase of $53.4 million in depreciation on our other generating facilities primarily related to the installation of emission control equipment at our Brandon Shores coal-fired generating plant that went into service in the fourth quarter of 2009, the Texas combined cycle generation facilities we acquired in 2010, and the Hillabee Energy Center, which began commercial dispatch in 2010.

Taxes Other Than Income Taxes

Our Generation business incurred higher taxes other than income taxes of $21.5 million in 2011 compared to 2010, primarily due to an increase in property taxes related to generating facilities acquired in Texas in 2010 and Massachusetts in 2011.

        Our Generation business incurred lower taxes other than income taxes of $43.8 million in 2010 compared to 2009, primarily due to lower property taxes as a result of the deconsolidation of CENG on November 6, 2009.

Equity Investment Earnings (Losses)

During 2011, our equity investment earnings decreased $5.2 million as compared to 2010, primarily due to lower CENG operating results of $27.9 million, partially offset by the absence of $16.8 million of losses on our investment in UNE, which was sold in 2010.

        During 2010, our equity investment earnings increased $24.8 million as compared to 2009, primarily due to $19.3 million of higher earnings from our investment in CENG, $7.9 million of lower losses from our investment in UNE, which was sold in 2010, partially offset by $2.4 million of lower earnings on investments in power projects.

        In December 2011, CENG's wholly owned subsidiary, Nine Mile Point, entered into a three year agreement with the applicable tax jurisdictions in New York State with respect to property tax payments on the Nine Mile Point nuclear generating facility. The agreement will not materially increase future property tax expenses for CENG for the term of the agreement and, as a result, will not materially impact our equity investment earnings in CENG based on our 50.01% ownership interest. The agreement also will result in settlement and discontinuance of all pending property tax assessment litigation proceedings between Nine Mile Point and the tax jurisdictions.

Gain on Settlements with DOE

During 2011, we recognized $93.8 million in pre-tax gains related to agreements with the DOE that settled the lawsuits that sought to recover damages caused by the DOE's failure to comply with legal and contractual obligations to dispose of spent nuclear fuel at the Calvert Cliffs nuclear power plant and the Ginna nuclear power plant. The lawsuit related to the Nine Mile Point nuclear power plant remains outstanding. We discuss these settlements in more detail in Note 2 to Consolidated Financial Statements.

NewEnergy Business

Background

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

        Our NewEnergy business focuses on delivery of physical, customer-oriented energy products and solutions to energy producers and consumers, manages the risk and optimizes the value of our owned and contracted generation assets and NewEnergy activities, and uses our portfolio management and trading capabilities both to manage risk and to deploy limited risk capital. Our NewEnergy business actively transacts in energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions.

        We record NewEnergy revenues and expenses in our financial results in different periods depending upon the appropriate accounting treatment that represents the economics of the underlying transactions in our business. We discuss our revenue recognition policies in the Critical Accounting Policies section and Note 1 to Consolidated Financial Statements.


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Results

 
  2011
  2010
  2009
 
   
 
  (In millions)
 

Revenues

  $ 10,120.2   $ 10,121.4   $ 11,509.2  

Fuel and purchased energy expenses

    (9,071.6 )   (8,877.6 )   (10,430.0 )
   

Gross margin

    1,048.6     1,243.8     1,079.2  

Operating expenses

    (843.1 )   (758.7 )   (763.6 )

Merger costs

    (26.4 )       (44.0 )

Impairment losses and other costs

        (0.1 )   (98.1 )

Workforce reduction costs

            (12.6 )

Depreciation, depletion, accretion, and amortization

    (89.4 )   (83.7 )   (82.7 )

Taxes other than income taxes

    (70.2 )   (52.8 )   (41.2 )

Equity investment (losses) earnings

            (6.3 )

Net gain (loss) on divestitures

    57.3     2.5     (468.8 )
   

Income (Loss) from Operations

  $ 76.8   $ 351.0   $ (438.1 )
   

Net Income (Loss)

  $ 2.8   $ 176.2   $ (348.2 )
   

Net (Loss) Income attributable to common stock

  $ (17.5 ) $ 138.6   $ (402.3 )
   

Change from prior year

  $ (156.1 ) $ 540.9        
   


Other Items Included in Operations (after-tax):


 

 

 

 

Merger costs

  $ (16.1 ) $   $ (4.1 )

International coal contract dispute settlement

        35.4      

Credit facility amendment/termination fees

    (5.8 )   (4.6 )   (24.0 )

Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits

        (0.1 )    

International commodities operation and gas trading operation (1)

            (371.9 )

Impairment losses and other costs

            (84.7 )

Workforce reduction costs

            (9.3 )
   

Total Other Items

  $ (21.9 ) $ 30.7   $ (494.0 )
   

Change from prior year

  $ (52.6 ) $ 524.7        
   

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 were 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 for 2009 also include amounts related to the operations we divested.

Revenues

Our NewEnergy revenues were essentially unchanged in 2011 compared to 2010 and decreased $1,387.8 million in 2010 compared to 2009 primarily due to the following:

 
  2011
vs. 2010

  2010
vs. 2009

 
   
 
  (In millions)
 

Realization of higher (lower) wholesale load sales

  $ 463   $ (917 )

Decrease in volume and contract prices related to our domestic coal operation

    (24 )   (508 )

Realization of (lower) higher retail power load sales

    (118 )   398  

Decrease due to the assignment of international coal and freight contracts, which we divested throughout 2009 and 2010

    (175 )   (321 )

Gain on sale of in-the-money wholesale load contract in the second quarter of 2009

        (106 )

Change in volumes at our retail gas and wholesale gas operation

    (92 )   (77 )

(Decrease) increase in wholesale mark-to-market revenues due to changes in power and gas prices

    (274 )   77  

Increase due to acquisitions of StarTex and MXenergy

    317      

All other

    (98 )   66  
   

Total decrease in NewEnergy revenues

  $ (1 ) $ (1,388 )
   

Fuel and Purchased Energy Expenses

Our NewEnergy fuel and purchased energy expenses increased $194.0 million in 2011 compared to 2010 and decreased $1,552.4 million in 2010 compared to 2009 primarily due to the following:

 
  2011
vs. 2010

  2010
vs. 2009

 
   
 
  (In millions)
 

Realization of fuel and purchased energy from wholesale power purchases

  $ 306   $ (641 )

Decrease due to the assignment of international coal and freight contracts, which we divested throughout 2009 and 2010

    (77 )   (540 )

Decrease in volume and contract prices related to our domestic coal operation

    (23 )   (498 )

(Decrease) increase in (prices) volumes of retail power load purchases

    (154 )   217  

Change in volumes at our retail gas and wholesale gas operation

    (54 )   (83 )

Increase due to acquisitions of StarTex and MXenergy

    236      

All other

    (40 )   (7 )
   

Total increase (decrease) in NewEnergy fuel and purchased energy expenses

  $ 194   $ (1,552 )
   

        From time to time, we may terminate or restructure contracts to lower our exposure to various risks under these contracts. During 2011, we terminated three contracts that increased gross margin by $26.9 million:

    $12.7 million related to the partial termination of a firm gas transportation capacity contract in order to mitigate risk on the last two years of the contract,
    $8.2 million related to the termination of certain in-the-money load-serving contracts in an effort to


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      mitigate variable load risk and reduce the impact of future commodity price changes on future gross margin, and

    $6.0 million related to an energy purchase contract that was terminated in order to eliminate the unit contingent risk associated with the energy purchase.

        The decrease in gross margin for 2011 compared to 2010 included a less favorable price environment in the Texas region due to two discrete events. In the first quarter of 2011, the Texas region experienced sudden, extreme drops in temperature, coupled with high winds. This weather event caused generation to go off-line and forced generators and load serving entities, like us, to purchase replacement power at significantly increased spot prices. Additionally, in the third quarter of 2011, the Texas region incurred extreme high temperatures for a prolonged period of time. This heat wave was compounded by fossil generator outages and a lack of wind plant availability throughout the region which led to price spikes well above historical averages for replacement power we had to purchase.

Mark-to-Market

Mark-to-market results include net gains and losses from origination, risk management, certain physical energy delivery activities, 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 and 2010, we focused our activities on reducing capital requirements, reducing long-term economic risk, and reducing short- and interim-term liquidity requirements. These actions impacted the results of the NewEnergy business, particularly the size of and potential for changes in fair value of activities subject to mark-to-market accounting in 2011 and will impact the results in future years.

        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 NewEnergy business 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. We recorded a $14.8 million pre-tax origination gain related to one transaction in 2011. In 2011, our NewEnergy business amended a nonderivative capacity sales contract such that the amended contract met the definition of a derivative subject to mark-to-market accounting. Simultaneous with the amending of the nonderivative contract, we executed at current market value a new derivative capacity purchase contract subject to mark-to-market accounting. The combination of these transactions resulted in substantially all of the origination gains presented for 2011 as well as mitigated our risk exposure under the amended contracts.

        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:

 
  2011
  2010
  2009
 
   
 
  (In millions)
 

Unrealized mark-to-market results

                   

Origination gains

  $ 14.8   $   $  

Risk management and trading—mark-to-market

                   

Unrealized changes in fair value

    (279.1 )   9.6     (212.3 )

Changes in valuation techniques

             

Reclassification of settled contracts to realized

    (78.4 )   (139.0 )   (265.4 )
   

Total risk management and trading—mark-to-market

    (357.5 )   (129.4 )   (477.7 )
   

Total unrealized mark-to-market (1)

    (342.7 )   (129.4 )   (477.7 )

Realized mark-to-market

    78.4     139.0     265.4  
   

Total mark-to-market results (2)

  $ (264.3 ) $ 9.6   $ (212.3 )
   
(1)
Total unrealized mark-to-market is the sum of origination transactions and total risk management and trading—mark-to-market.

(2)
Includes gains (losses) on hedge ineffectiveness for fair value hedges recorded in gross margin.

        Total mark-to-market results decreased $273.9 million during the year ended December 31, 2011 compared to the same period of 2010 due to unrealized changes in fair value primarily due to:

    $211 million of lower results on open positions in our power and transmission management activities within the NEPOOL and PJM regions due to a less favorable price environment,
    $34 million related to unrealized positions in our retail power and gas operations,
    $19 million related to economic hedges of our upstream natural gas operations due to a less favorable price environment, and
    $10 million related to our domestic coal portfolio due to a less favorable price environment.


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        Total mark-to-market results increased $221.9 million during the year ended December 31, 2010 compared to the same period of 2009 due to unrealized changes in fair value primarily due to:

    $197 million of higher results on open positions primarily due to the absence of losses in our power and transmission risk management activities in the PJM, Midwest, New York, and West regions as a result of a favorable price environment in 2010 and completion of our activities to reduce risk and improve liquidity,
    $31 million of higher gains on open positions primarily due to the absence of losses in 2010 resulting from a more favorable price environment related to our retail power and gas businesses,
    $18 million of higher results in our domestic coal portfolio primarily due to a more favorable price movement, and
    $16 million of higher results on open positions due to a more favorable price environment related to economic hedges of our upstream gas operations and risk management activities.

        These increases were partially offset by the absence of $40 million in results from our international coal and freight operations, which we divested in 2009.

Derivative Assets and Liabilities

Derivative assets and liabilities consisted of the following:

At December 31,
  2011
  2010
 
   
 
  (In millions)
 

Current assets

  $ 357.9   $ 534.4  

Noncurrent assets

    259.3     258.9  
   

Total assets

    617.2     793.3  
   

Current liabilities

    779.5     622.3  

Noncurrent liabilities

    268.4     353.0  
   

Total liabilities

    1,047.9     975.3  
   

Net derivative position

  $ (430.7 ) $ (182.0 )
   

Composition of net derivative exposure:

             

Hedges

  $ (224.2 ) $ (504.5 )

Mark-to-market

    (63.1 )   350.3  

Net cash collateral included in derivative balances

    (143.4 )   (27.8 )
   

Net derivative position

  $ (430.7 ) $ (182.0 )
   

Derivative balances above include noncurrent assets related to our Generation business of $48.9 million and $35.7 million at December 31, 2011 and December 31, 2010, respectively. Derivative balances related to our Generation business consist of interest rate contracts accounted for as fair value hedges.

        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 $280.3 million in our net derivative liability subject to hedge accounting since December 31, 2010 was due to $535.3 million of realization of out-of-the-money cash-flow hedges at the time the forecasted transaction occurred, partially offset by $255.0 million of increases on our out-of-the-money cash-flow hedge positions primarily related to decreases in power, natural gas, and coal prices during 2011.

        The increase in cash collateral held primarily relates to transactions with one counterparty, and, as a result of the decrease in power prices, our positions are more in-the-money, requiring the counterparty to provide us with more cash collateral.

        The following are the primary sources of the change in our net derivative asset (liability) subject to mark-to-market accounting during 2011 and 2010:

 
  2011
  2010
 
   
 
  (In millions)
 

Fair value beginning of year

        $ 350.3         $ 524.3  

Changes in fair value recorded in earnings

                         

Origination gains

  $ 14.8         $        

Unrealized changes in fair value

    (279.1 )         9.6        

Changes in valuation techniques

                     

Reclassification of settled contracts to realized

    (78.4 )         (139.0 )      
                       

Total changes in fair value

          (342.7 )         (129.4 )

Changes in value of exchange-listed futures and options

          (215.8 )         (197.1 )

Net change in premiums on options

          (40.2 )         17.7  

Contracts acquired

          (7.4 )         5.4  

Dedesignated contracts and other changes in fair value

          192.7           129.4  
   

Fair value at end of year

        $ (63.1 )       $ 350.3  
   

        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


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      settled during the period and recorded as realized revenues.

        The net derivative asset also changed due to the following items:

    Changes in value of exchange-listed futures and options are 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.
    Dedesignated contracts and other changes in fair value primarily represent realization of the value of derivative contracts previously transferred from cash-flow hedges to mark-to-market or from mark-to-market to cash-flow hedges.

        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, 2011:

 
  Settlement Term    
 
 
  2012
  2013
  2014
  2015
  2016
  2017
  Thereafter
  Fair Value
 
   
 
  (In millions)
 

Level 1

  $ (1.7 ) $   $   $   $   $   $   $ (1.7 )

Level 2

    (33.3 )   (19.1 )   (7.6 )   14.5     16.1     2.1     (0.2 )   (27.5 )

Level 3

    50.4     (34.7 )   (11.6 )   (9.0 )   (11.2 )   (8.6 )   (9.2 )   (33.9 )
   

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

  $ 15.4   $ (53.8 ) $ (19.2 ) $ 5.5   $ 4.9   $ (6.5 ) $ (9.4 ) $ (63.1 )
   

        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 NewEnergy business, we expect to realize the value of these contracts, as well as any contracts we may enter into in the future to manage our risk, over time as the contracts and related hedges settle in accordance with their terms. 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 NewEnergy business operating expenses increased $84.4 million during 2011 as compared to 2010 due to growth in this business segment: primarily $31.3 million and $35.8 million, respectively, due to the acquisitions of StarTex (May 2011) and MXenergy (July 2011), and $11.5 million due to an increase in marketing and advertising related to our residential electricity program.

Merger Costs

We discuss costs related to the proposed merger with Exelon in more detail in Note 2 to Consolidated Financial Statements.

Taxes Other Than Income Taxes

Our NewEnergy business incurred higher taxes other than income taxes of $17.4 million in 2011 compared to 2010, primarily due to higher gross receipts taxes related to an increase in retail revenues, primarily in Pennsylvania.

        Our NewEnergy business incurred higher taxes other than income taxes of $11.6 million in 2010 compared to 2009, primarily due to higher gross receipts taxes related to an increase in retail revenues, primarily in Pennsylvania.


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Net Gain (Loss) on Divestitures

The table below summarizes the net pre-tax gain (loss) on divestitures for our NewEnergy business:

 
  2011
  2010
  2009
 
   

Upstream working interests

  $ 23.6   $   $  

Interests in CEP

    33.7          

Majority of our international commodities operation

            (334.5 )

Houston-based gas trading operation

            (102.5 )

Uranium market participant

            (27.2 )

Portfolio of contracts in our retail gas operations

        2.0      

Other

        0.5     (4.6 )
   

Total net gain (loss) on divestiture

  $ 57.3   $ 2.5   $ (468.8 )
   

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

Regulated Electric Business

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

Results

 
  2011
  2010
  2009
 
   
 
  (In millions)
 

Revenues

  $ 2,321.4   $ 2,752.3   $ 2,820.7  

Electricity purchased for resale expenses

    (1,184.7 )   (1,680.9 )   (1,840.9 )

Operations and maintenance expenses

    (505.8 )   (449.3 )   (399.0 )

Merger costs

    (22.6 )        

Depreciation and amortization

    (226.5 )   (205.2 )   (218.1 )

Taxes other than income taxes

    (154.9 )   (149.1 )   (142.9 )
   

Income from Operations

  $ 226.9   $ 267.8   $ 219.8  
   

Net Income

  $ 93.6   $ 110.0   $ 79.1  
   

Net Income attributable to common stock

  $ 83.8   $ 99.8   $ 68.9  
   

Other Items Included in Operations (after-tax):

       

Hurricane Irene incremental storm expenses

  $ (24.6 ) $   $  

Merger costs (1)

    (13.3 )        

Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits

        (3.1 )    

Residential customer rate credit

            (56.7 )
   

Total Other Items

  $ (37.9 ) $ (3.1 ) $ (56.7 )
   

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)
BGE will not seek recovery of these costs in rates.

        Net income attributable to common stock from the regulated electric business decreased $16.0 million in 2011 compared to 2010, primarily due to an increase in incremental restoration expenses related to Hurricane Irene of $24.6 million after-tax and a $12.7 million after-tax increase in depreciation and amortization. These increases in expenses were partially offset by an increase in base rate distribution revenues of $18.0 million after-tax resulting from the December 2010 Maryland PSC rate order.

        Net income attributable to common stock from the regulated electric business increased $30.9 million in 2010 compared to 2009, mostly due to the absence in 2010 of $56.7 million after-tax in credits provided to customers in 2009 and a $7.7 million after-tax decrease in depreciation and amortization, partially offset by a $30.3 million after-tax increase in operations and maintenance expenses.

Electric Revenues

The changes in electric revenues in 2011 and 2010 compared to the respective prior year were caused by:

 
  2011
vs. 2010

  2010
vs. 2009

 
   
 
  (In millions)
 

Distribution volumes

  $ (3.5 ) $ 32.7  

Base rates

    27.7     3.3  

Residential customer rate credit

        95.0  

Smart Energy Savers Program® surcharges

    12.1     (22.0 )

Revenue decoupling

    16.5     (30.9 )

Standard offer service

    (502.5 )   (154.2 )

Rate stabilization recovery

    (7.1 )   2.5  

Financing credits

    (2.7 )   0.4  

Senate Bill 1 credits

    1.0     (12.9 )
   

Total change in electric revenues from electric system sales

    (458.5 )   (86.1 )

Other

    27.6     17.7  
   

Total change in electric revenues

  $ (430.9 ) $ (68.4 )
   

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 2011 and 2010 compared to the respective prior year were:

 
  2011
  2010
 
   

Residential

    (9.3 )%   7.6 %

Commercial

    1.4     3.5  

Industrial

    (0.4 )   (8.0 )

        In 2011, we distributed less electricity to residential customers due to milder weather, partially offset by increased usage per customer and an increased number of customers. We distributed more electricity to commercial customers due to increased usage per customer and an increased number of customers, partially offset by milder weather. We distributed less electricity to industrial customers primarily due to a decreased usage per customer.

        In 2010, we distributed more electricity to residential and commercial customers due to warmer summer and colder fourth quarter weather and an increased number of customers. We distributed less electricity to industrial customers primarily due to decreased usage per customer.


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Base Rates

On December 6, 2010, the Maryland PSC issued an abbreviated order authorizing BGE to increase electric distribution rates by $31.0 million for service rendered on or after December 4, 2010. This increase was based upon an 8.06% rate of return with a 9.86% return on equity and a 52% equity ratio. We discuss BGE's electric base rates in the Regulation—Maryland—Base Rates section.

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 applied to BGE residential electric customer bills in the first quarter of 2010.

Smart Energy Savers Program® 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 through the use of customer bill credits.

        Revenues increased in 2011 compared to 2010, primarily due to an increase in the customer surcharge rates in 2011.

        Revenues declined in 2010 compared to 2009, primarily due to an increase in customer involvement in our programs. This increased participation increased customer credits and, therefore, decreased revenues.

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 (except as discussed below with regard to major storms) 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.

        In January 2012, the Maryland PSC issued an order prospectively prohibiting Maryland electric utilities with a revenue decoupling mechanism from collecting a certain portion of decoupling revenue during major storm events if customer service is not restored within a specified period of time. We do not expect the impact of this prohibition to have a material effect on our, or BGE's, financial results.

Standard Offer Service

BGE provides standard offer service for customers that do not select an alternative supplier.

        Standard offer service revenues decreased in 2011 compared to 2010 mostly due to a decrease in standard offer service volumes of 20% and a decrease in standard offer service rates of 15%. The volume decrease is primarily due to an increase in customers using competitive suppliers, while the decrease in service rates was due to the decreased cost of purchased electricity for the period.

        Standard offer service revenues decreased in 2010 compared to 2009 mostly due to lower standard offer service rates and lower standard offer service volumes.

Rate Stabilization Recovery

In late June 2007, BGE began recovering amounts deferred during the first rate deferral period that began in July 2006 and ended on May 31, 2007. The recovery of the first rate stabilization plan is occurring over a ten year period. In April 2008, BGE began recovering amounts deferred during the second rate deferral period that began in June 2007 and 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.

        Rate stabilization recovery revenue decreased during 2011 compared to 2010 primarily due to a decrease in volumes, partially offset by increased recovery rates charged to customers.

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 a 2008 Maryland settlement agreement, 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.


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        The decrease in revenues during 2010 compared to 2009 is primarily due to the reinstatement of the credit for the residential return component of the administrative charge on June 1, 2010 and higher 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:

 
  2011
  2010
  2009
 
   
 
  (In millions)
 

Actual costs

  $ 1,128.3   $ 1,618.3   $ 1,781.9  

Recovery under rate stabilization plans

    56.4     62.6     59.0  
   

Electricity purchased for resale expenses

  $ 1,184.7   $ 1,680.9   $ 1,840.9  
   

Actual Costs

BGE's actual costs for electricity purchased for resale decreased $490.0 million for 2011 compared to 2010, primarily due to lower contract prices to purchase electricity for our customers and lower volumes due to an increase in customers using competitive suppliers.

        BGE's actual costs for electricity purchased for resale decreased $163.6 million for 2010 compared to 2009, mostly due to lower standard offer service rates and volumes.

Recovery under Rate Stabilization Plans

BGE deferred electricity purchased for resale expenses representing the difference between our actual costs of electricity purchased for resale and what we are allowed to bill customers under our rate stabilization plan. These deferred expenses, plus carrying charges, are included in "Regulatory Assets (net)" in our, and BGE's, Consolidated Balance Sheets.

        In late June 2007, we began recovering previously deferred amounts from customers. We recovered $56.4 million, $62.6 million, and $59.0 million in 2011, 2010, and 2009, respectively, 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 $56.5 million in 2011 compared to 2010, primarily due to:

    incremental restoration expenses related to Hurricane Irene of $41.1 million,
    $12.9 million in increased distribution service restoration expenses associated with 2011 winter storms, and
    $7.3 million in higher labor and benefit costs and the impact of inflation on other costs of $3.9 million.

        These increases were partially offset by a $12.6 million reduction in operations and maintenance expenses due to incremental restoration expenses associated with 2010 storms and other costs that were deferred as regulatory assets in 2011 as required by the Maryland PSC in its comprehensive rate case order received in March 2011.

        Regulated electric operations and maintenance expenses increased $50.3 million in 2010 compared to 2009, primarily due to increased distribution service restoration expenses of $24.2 million, $13.4 million of higher labor and benefits costs, and the impact of inflation on other costs of $12.7 million.

Merger Costs

We discuss costs related to the proposed merger with Exelon in more detail in Note 2 to Consolidated Financial Statements. However, BGE will not seek recovery of these costs in rates.

Electric Depreciation and Amortization Expense

Regulated electric depreciation and amortization expense increased $21.3 million during 2011, compared to 2010, primarily due to increased amortization of $13.2 million of deferred Smart Energy Savers Program® costs due to an increase in program surcharges, and an increase in property, plant and equipment depreciation of $9.5 million.

        Regulated electric depreciation and amortization expense decreased $12.9 million during 2010, compared to 2009, primarily due to decreased amortization of $22.9 million of deferred Smart Energy Savers Program® costs due to a regulatory change in the deferral period associated with these costs, partially offset by an increase in property, plant and equipment depreciation of $7.0 million.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $5.8 million during 2011 compared to 2010, primarily due to an increase in property taxes of $5.2 million.

        Taxes other than income taxes increased $6.2 million during 2010 compared to 2009, primarily due to the absence in 2010 of the impact of lower customer credits on franchise taxes of $95.0 million pre-tax.


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Regulated Gas Business

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

Results

 
  2011
  2010
  2009
 
   
 
  (In millions)
 

Revenues

  $ 671.7   $ 709.4   $ 758.3  

Gas purchased for resale expenses

    (334.2 )   (387.5 )   (449.9 )

Operations and maintenance expenses

    (161.0 )   (156.8 )   (160.9 )

Merger costs

    (7.7 )        

Depreciation and amortization

    (45.6 )   (44.0 )   (44.0 )

Taxes other than income taxes

    (35.3 )   (34.7 )   (34.9 )
   

Income from Operations

  $ 87.9   $ 86.4   $ 68.6  
   

Net Income

  $ 42.1   $ 37.6   $ 25.5  
   

Net Income attributable to common stock

  $ 38.7   $ 34.6   $ 22.5  
   


Other Items Included in Operations (after-tax):


 

 

 

 

 

 

 

 

 

 

Merger costs(1)

  $ (4.5 ) $   $  

Residential customer rate credit

            (10.4 )
   

Total Other Items

  $ (4.5 ) $   $ (10.4 )
   

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

(1)
BGE will not seek recovery of these costs in rates.

        Net income attributable to common stock from the regulated gas business increased $4.1 million in 2011 compared to 2010, primarily due to an increase in base rate distribution revenues of $5.2 million after-tax resulting from the December 2010 Maryland PSC rate order

        Net income attributable to common stock from the regulated gas business increased $12.1 million in 2010 compared to 2009, primarily due to the absence in 2010 of the accrual of a customer rate credit of $10.4 million after-tax recorded in 2009.

Gas Revenues

The changes in gas revenues in 2011 and 2010 compared to the respective prior year were caused by:

 
  2011
vs. 2010

  2010
vs. 2009

 
   
 
  (In millions)
 

Distribution volumes

  $ 6.4   $ 3.1  

Base rates

    8.2     1.6  

Residential customer rate credit

        17.4  

Conservation surcharge

    1.7     (1.0 )

Revenue decoupling

    (5.5 )   (3.1 )

Gas cost adjustments

    (50.6 )   (69.1 )
   

Total change in gas revenues from gas system sales

    (39.8 )   (51.1 )

Off-system sales

    1.9     (1.2 )

Other

    0.2     3.4  
   

Total change in gas revenues

  $ (37.7 ) $ (48.9 )
   

Distribution Volumes

The percentage changes in our distribution volumes, by type of customer, in 2011 and 2010 compared to the respective prior year were:

 
  2011
  2010
 
   

Residential

    (7.0 )%   1.1 %

Commercial

    4.5     (3.2 )

Industrial

    (13.5 )   (5.2 )

        In 2011, we distributed less gas to residential customers due to milder weather, partially offset by increased usage per customer and an increased number of customers. We distributed more gas to commercial customers, mostly due to increased usage per customer and an increased number of customers, partially offset by milder weather. We distributed less gas to industrial customers, mostly due to decreased usage per customer.

        In 2010, we distributed more gas to residential customers, mostly due to increased usage per customer and an increased number of customers. We distributed less gas to commercial customers, mostly due to decreased usage per customer. We distributed less gas to industrial customers, mostly due to decreased usage per customer.

Base Rates

On December 6, 2010, the Maryland PSC issued an abbreviated order authorizing BGE to increase gas distribution rates by $9.8 million for service rendered on or after December 4, 2010. This increase was based upon a 7.90% rate of return with a 9.56% return on equity and a 52% equity ratio. We discuss BGE's gas base rates in the Regulation—Maryland—Base Rates section.

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 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 gas customers was $17.4 million pre-tax. This credit was accrued in the fourth quarter of 2009 and applied to BGE residential gas customer bills in the first quarter of 2010.

Conservation Surcharge

Beginning February 2009, the Maryland PSC approved a customer surcharge through which BGE recovers costs associated with certain programs designed to help BGE encourage customer conservation. In 2010, this surcharge was expanded to include the recovery of costs associated with BGE's demand response program.


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Table of Contents

Gas Revenue Decoupling

The Maryland PSC allows us to record a monthly adjustment to our gas distribution revenues to eliminate the effect of abnormal weather and usage patterns per customer on our gas distribution volumes, 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.

Gas Cost Adjustments

We charge our gas customers for the natural gas they purchase from us using gas cost adjustment clauses set by the Maryland PSC as described in Note 1 to Consolidated Financial Statements. However, under the market-based rates mechanism approved by the Maryland PSC, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers.

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

        Gas cost adjustment revenues decreased in both 2011 compared to 2010 and in 2010 compared to 2009 because we sold less gas at lower prices.

Off-System Gas Sales

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

        Revenues from off-system gas sales increased in 2011 compared to 2010 primarily due to higher volumes, partially offset by lower prices.

        Revenues from off-system gas sales decreased in 2010 compared to 2009 because we sold less gas, partially offset by higher prices.

Gas Purchased For Resale Expenses

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

        Gas costs decreased $53.3 million in 2011 compared to 2010 and decreased $62.4 million in 2010 compared to 2009 because we purchased less gas at lower prices.

Gas Operations and Maintenance Expenses

Regulated gas operation and maintenance expenses increased $4.2 million during 2011 compared to 2010, primarily due to higher labor and benefits costs and the impact of inflation.

        Regulated gas operation and maintenance expenses decreased $4.1 million during 2010 compared to 2009, primarily due to decreased uncollectible accounts receivable expense of $4.7 million.

Merger Costs

We discuss costs related to the proposed merger with Exelon in more detail in Note 2 to Consolidated Financial Statements. However, BGE will not seek recovery of these costs in rates.

Holding Company and Other Nonregulated Businesses

Results

 
  2011
  2010
  2009
 
   
 
  (In millions)
 

Revenues

  $ 1.7   $ 1.2   $ 14.4  

Operating expenses