**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

**FORM 10-K**

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**ANNUAL REPORTPURSUANT TO SECTION 13 OR 15(D) OFTHE SECURITIES EXCHANGE ACT OF 1934**

For the fiscal year ended **DECEMBER31, 2006**

| Commission  file number |   | Exact name of registrant as specified in its charter |   | IRS Employer  Identification No. |
|-------------------------|--------|------------------------------------------------------|--------|----------------------------------|
| **1-12869**             |   | **CONSTELLATION ENERGY GROUP, INC.**                 |   | **52-1964611**                   |
| **1-1910**              |   | **BALTIMORE  GAS AND ELECTRIC COMPANY**              |   | **52-0280210**                   |

 
|            | ** **                                                                                                           | ** **                                                 | **MARYLAND** | ** ** | ** ** | ** ** |
|------------|----------------------------------------------------------------------------------------------------------------------|------------------------------------------------------------|--------------|------------|------------|------------|
|       | ** **                                                                                                           | (States of  incorporation)                                 | ** **   | ** ** |
|       | **750 E.  PRATT STREET       BALTIMORE, MARYLAND      21202** | ** **                                                 |
|       |                                                                                                                 | (Address of  principal executive offices)                  |         | (Zip Code) |
| ** ** | ** **                                                                                                           | **410****-****783****-****2800**                           | ** **   | ** ** |
|       |                                                                                                                 | (Registrants’ telephone  number, including area code) |         |       |
|            |                                                                                                                      |                                                            |              |            |            |            |  |  |  |  |

 

**SECURITIESREGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:**
|                                                                                                                                                                                                                               | ** **              | **Name of each  exchange on**                               |
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-------------------------|-------------------------------------------------------------|
| ** **                                                                                                                                                                                                                    | **Title of each class** | ** **                                                  | ** ** | ** ** | **which registered** | ** ** |
| Constellation Energy Group, Inc. Common Stock—Without Par Value                                                                                                                                                          | }                       | New York Stock Exchange, Inc.  Chicago Stock Exchange, Inc. |
| 6.20% Trust Preferred Securities ($25 liquidation  amount per preferred security) issued by BGE Capital Trust II, fully and  unconditionally guaranteed, based on several obligations, by Baltimore Gas  and Electric Company | }                       | New York Stock Exchange, Inc.                               |
|                                                                                                                                                                                                                               |                         |                                                             |  |  |  |  |

 

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

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

Indicate by check mark if Baltimore Gas and ElectricCompany is a well-known seasoned issuer, as defined in Rule 405 of theSecurities Act. Yes x   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) ofthe Act. Yes o   No x.

Indicate by check mark if Baltimore Gas and ElectricCompany is not required to file reports pursuant to Section 13 or Section 15(d) ofthe Act. Yes o   No x.

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

Indicate by check mark if disclosure of delinquentfilers pursuant to Item 405 of Regulation S-K is not contained herein, andwill not be contained, to the best of registrants’ knowledge, in definitiveproxy or information statements incorporated by reference in Part III ofthis Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether Constellation EnergyGroup, Inc. is a large accelerated filer, an accelerated filer, or anon-accelerated filer. See definition of “accelerated filer” and “largeaccelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x   Acceleratedfiler o   Non-accelerated filer o

Indicate by check mark whether Baltimore Gas andElectric Company is a large accelerated filer, an accelerated filer, or anon-accelerated filer. See definition of “accelerated filer” and “largeaccelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o    Acceleratedfiler o   Non-accelerated filer x

Indicate by check mark whether Constellation EnergyGroup, Inc. is a shell company (as defined in Rule 12b-2 of theExchange Act) Yes o   No x

Indicate by check mark whether Baltimore Gas andElectric Company is a shell company (as defined in Rule 12b-2 of theExchange Act) Yes o   No x

Aggregate market value of Constellation Energy Group, Inc.Common Stock, without par value, held by non-affiliates as of June 30,2006 was approximately $9,699,558,195 based upon New York Stock Exchangecomposite transaction closing price.

**CONSTELLATION ENERGYGROUP, INC. COMMON STOCK, WITHOUT PAR VALUE180,679,592 SHARES OUTSTANDING ON JANUARY 31, 2007.**

**DOCUMENTS INCORPORATED BYREFERENCE**
| Part of Form 10-K | ** ** | ** **                                                                                                                | **Document Incorporated by Reference** | ** ** |
|----------------------------------|------------|---------------------------------------------------------------------------------------------------------------------------|----------------------------------------|------------|
| III                              |       | Certain sections of the Proxy Statement for the 2007 Annual Meeting of  Shareholders for Constellation Energy Group, Inc. |

 

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

 

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**TABLEOF CONTENTS**
|               | ** ** |        | ** ** | ** **                                                                                                                        | ** ** | **Page** |
|---------------|------------|--------|------------|-----------------------------------------------------------------------------------------------------------------------------------|------------|----------|
|          |       |   |       | Forward  Looking Statements                                                                                                       |       | 1        |   |
| PART I   |       |   |       |                                                                                                                              |       |     |   |
| Item 1        |       | — |       | Business                                                                                                                          |       | 2        |   |
|          |       |   |       | Overview                                                                                                                          |       | 2        |   |
|          |       |   |       | Merchant  Energy Business                                                                                                         |       | 3        |   |
|          |       |   |       | Baltimore Gas and Electric Company                                                                                                |       | 10       |   |
|          |       |   |       | Other Nonregulated Businesses                                                                                                     |       | 15       |   |
|          |       |   |       | Consolidated Capital Requirements                                                                                                 |       | 15       |   |
|          |       |   |       | Environmental  Matters                                                                                                            |       | 15       |   |
|          |       |   |       | Employees                                                                                                                         |       | 17       |   |
| Item 1A       |       | — |       | Risk  Factors                                                                                                                     |       | 18       |   |
| Item 2        |       | — |       | Properties                                                                                                                        |       | 22       |   |
| Item 3        |       | — |       | Legal  Proceedings                                                                                                                |       | 24       |   |
| Item 4        |       | — |       | Submission of Matters to Vote of Security Holders                                                                                 |       | 24       |   |
|          |       |   |       | Executive Officers of the Registrant (Instruction 3 to  Item 401(b) of Regulation S-K)                        |       | 25       |   |
| PART II  |       |   |       |                                                                                                                              |       |     |   |
| Item 5        |       | — |       | Market for Registrant’s Common Equity and Related Shareholder Matters                                                        |       | 27       |   |
| Item 6        |       | — |       | Selected Financial Data                                                                                                           |       | 28       |   |
| Item 7        |       | — |       | Management’s Discussion and Analysis of Financial Condition and  Results of Operations                                       |       | 30       |   |
| Item 7A       |       | — |       | Quantitative and Qualitative Disclosures  About Market Risk                                                                       |       | 63       |   |
| Item 8        |       | — |       | Financial Statements and Supplementary Data                                                                                       |       | 64       |   |
| Item 9        |       | — |       | Changes in and Disagreements with Accountants on Accounting and  Financial Disclosure                                             |       | 121      |   |
| Item 9A       |       | — |       | Controls and Procedures                                                                                                           |       | 121      |   |
| Item 9B       |       | — |       | Other  Information                                                                                                                |       | 121      |   |
| PART III |       |   |       |                                                                                                                              |       |     |   |
| Item 10       |       | — |       | Directors and Executive Officers of the Registrant                                                                                |       | 122      |   |
| Item 11       |       | — |       | Executive Compensation                                                                                                            |       | 122      |   |
| Item 12       |       | — |       | Security Ownership of Certain Beneficial Owners and Management  and Related Shareholder Matters     |       | 122      |   |
| Item 13       |       | — |       | Certain Relationships and Related Transactions                                                                                    |       | 123      |   |
| Item 14       |       | — |       | Principal Accountant Fees and Services                                                                                            |       | 123      |   |
| PART IV  |       |   |       |                                                                                                                              |       |     |   |
| Item 15       |       | — |       | Exhibits and Financial Statement Schedules                                                                                        |       | 123      |   |
| Signatures    |       | 129    |       |

 

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**Forward Looking Statements**

We make statements in this report that are considered forward lookingstatements within the meaning of the Securities Exchange Act of 1934. Sometimesthese statements will contain words such as “believes,” “anticipates,” “expects,”“intends,” “plans,” and other similar words. We also disclose non-historicalinformation that represents management’s expectations, which are based onnumerous assumptions. These statements and projections are not guarantees ofour future performance and are subject to risks, uncertainties, and otherimportant factors that could cause our actual performance or achievements to bematerially different from those we project. These risks, uncertainties, andfactors include, but are not limited to:

 ̈  thetiming and extent of changes in commodity prices and volatilities for energyand energy related products including coal, natural gas, oil, electricity,nuclear fuel, freight, and emission allowances,

 ̈  theliquidity and competitiveness of wholesale markets for energy commodities,

 ̈  theeffect of weather and general economic and business conditions on energysupply, demand, and prices,

 ̈  theability to attract and retain customers in our competitive supply activitiesand to adequately forecast their energy usage,

 ̈  thetiming and extent of deregulation of, and competition in, the energy markets,and the rules and regulations adopted on a transitional basis in thosemarkets,

 ̈  uncertaintiesassociated with estimating natural gas reserves, developing properties, andextracting natural gas,

 ̈  regulatoryor legislative developments that affect deregulation, transmission ordistribution rates and revenues, demand for energy, or increases in costs,including costs related to nuclear power plants, safety, or environmentalcompliance,

 ̈  theinability of Baltimore Gas and Electric Company (BGE) to recover all its costsassociated with providing customers service,

 ̈  theconditions of the capital markets, interest rates, availability of credit,liquidity, and general economic conditions, as well as Constellation EnergyGroup’s (Constellation Energy) and BGE’s ability to maintain their currentcredit ratings,

 ̈  theeffectiveness of Constellation Energy’s and BGE’s risk management policies andprocedures and the ability and willingness of our counterparties to satisfytheir financial and performance commitments,

 ̈  operationalfactors affecting commercial operations of our generating facilities (includingnuclear facilities) and BGE’s transmission and distribution facilities,including catastrophic weather-related damages, unscheduled outages orrepairs, unanticipated changes in fuel costs or availability, unavailability ofcoal or gas transportation or electric transmission services, workforce issues,terrorism, liabilities associated with catastrophic events, and other eventsbeyond our control,

 ̈  theactual outcome of uncertainties associated with assumptions and estimates usingjudgment when applying critical accounting policies and preparing financialstatements, including factors that are estimated in determining the fair valueof energy contracts, such as the ability to obtain market prices and, in theabsence of verifiable market prices, the appropriateness of models and modelinputs (including, but not limited to, estimated contractual load obligations,unit availability, forward commodity prices, interest rates, correlation andvolatility factors),

 ̈  changesin accounting principles or practices,

 ̈  losseson the sale or write down of assets due to impairment events or changes inmanagement intent with regard to either holding or selling certain assets,

 ̈  theability to successfully identify and complete acquisitions and sales ofbusinesses and assets, and

 ̈  costand other effects of legal and administrative proceedings that may not becovered by insurance, including environmental liabilities.

Given theseuncertainties, you should not place undue reliance on these forward lookingstatements. Please see the other sections of this report and our other periodicreports filed with the Securities and Exchange Commission (SEC) for moreinformation on these factors. These forward looking statements represent ourestimates and assumptions only as of the date of this report.

Changes may occur after that date, and neither Constellation Energy norBGE assume responsibility to update these forward looking statements.

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**PART I**

**Item 1. Business**

**Overview**

Constellation Energy is anenergy company that includes a merchant energy business and BGE, a regulatedelectric and gas public utility in central Maryland.

Constellation Energy wasincorporated in Maryland on September 25, 1995. On April 30, 1999,Constellation Energy became the holding company for BGE and its subsidiaries.References in this report to “we” and “our” are to Constellation Energy and itssubsidiaries, collectively. References in this report to the “regulatedbusiness(es)” are to BGE.

Our merchantenergy business is a competitive provider of energy solutions for a variety ofcustomers. It has electric generation assets located in various regions of theUnited States and provides energy solutions to meet customers’ needs. Ourmerchant energy business focuses on serving the energy and capacityrequirements (load-serving) of, and providing other energy products and riskmanagement services, for various customers.

Our merchant energy business includes:

 ̈  ageneration operation that owns, operates, and maintains fossil, nuclear, andhydroelectric generating facilities and holds interests in qualifyingfacilities, fuel processing facilities and power projects in the United States,

 ̈  awholesale marketing, risk management, and trading operation that primarilyprovides energy products and services to distribution utilities, powergenerators, and other wholesale customers,

 ̈  anelectric and natural gas retail operation that provides energy products andservices to commercial, industrial, and governmental customers, and

 ̈  ageneration operations and maintenance services operation.

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

Our other nonregulated businesses:

 ̈  design,construct, and operate heating, cooling, and cogeneration facilities, andprovide various energy-related services, including energy consulting, forcommercial, industrial, and governmental customers throughout North America,and

 ̈  providehome improvements, service heating, air conditioning, plumbing, electrical, andindoor air quality systems, and provide natural gas to residential customers incentral Maryland.

On October 24,2006, Constellation Energy and FPL Group, Inc. (FPL Group) agreed toterminate the Agreement and Plan of Merger the parties entered into on December 18,2005. For additional information related to the merger termination, see *Note 15 to Consolidated Financial Statements*. For a discussion of other recent events that haveimpacted us, our strategy, and the seasonality of our business, please refer to*Item 7. Management’s Discussion andAnalysis* section.

ConstellationEnergy maintains a website at constellation.com where copies of our annualreports on Form 10-K, quarterly reports on Form 10-Q,current reports on Form 8-K, and any amendments may be obtained freeof charge. These reports are posted on our website the same day they are filedwith the SEC. The SEC maintains a website (sec.gov), where copies of our filingsmay be obtained free of charge. The website address for BGE is bge.com. Thesewebsite addresses are inactive textual references, and the contents of thesewebsites are not part of this Form 10-K.

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

The Principles of Business Integrity is a code of ethics that appliesto all of our directors, officers, and employees, including the chief executiveofficer, chief financial officer, and chief accounting officer. We will postany amendments to, or waivers from, the Principles of Business Integrityapplicable to our chief executive officer, chief financial officer, or chiefaccounting officer on our website.

**Operating Segments**

The percentages of revenues, net income, andassets attributable to our operating segments are shown in the tables below. Wepresent information about our operating segments, including certain otheritems, in *Note 3 to ConsolidatedFinancial Statements*.
| ** ** | ** ** | **Unaffiliated Revenues** | ** ** |
|------------|------------|--------------------------------|------------|
| ** ** | ** ** | **Merchant  Energy**           | ** ** | **Regulated  Electric** | ** ** | **Regulated  Gas** | ** ** | **Other  Nonregulated** | ** ** |
| 2006       |       |                           | 83         | % |   |   | 11 | % |   |   | 5 | % |   |   | 1 | % |   |
| 2005       |       |                           | 81         |   |   |   | 12 |   |   |   | 6 |   |   |   | 1 |   |   |
| 2004       |       |                           | 76         |   |   |   | 16 |   |   |   | 6 |   |   |   | 2 |   |   |

 
| ** ** | ** ** | **Net Income **(1) | ** ** |
|------------|------------|------------------------------|------------|
| ** ** | ** ** | **Merchant  Energy**         | ** ** | **Regulated  Electric** | ** ** | **Regulated  Gas** | ** ** | **Other  Nonregulated** | ** ** |
| 2006       |       |                         | 77         | % |   |   | 16 | % |   |   | 5 | % |   |   | 2 | % |   |
| 2005       |       |                         | 67         |   |   |   | 28 |   |   |   | 5 |   |   |   | — |   |   |
| 2004       |       |                         | 72         |   |   |   | 26 |   |   |   | 5 |   |   |   | (3 | ) |   |

 

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| ** ** | ** ** | **Total Assets** | ** ** |
|------------|------------|-----------------------|------------|
| ** ** | ** ** | **Merchant  Energy**  | ** ** | **Regulated  Electric** | ** ** | **Regulated  Gas** | ** ** | **Other  Nonregulated** | ** ** |
| 2006       |       |                  | 75         | % |   |   | 17 | % |   |   | 6 | % |   |   | 2 | % |   |
| 2005       |       |                  | 77         |   |   |   | 16 |   |   |   | 6 |   |   |   | 1 |   |   |
| 2004       |       |                  | 71         |   |   |   | 20 |   |   |   | 7 |   |   |   | 2 |   |   |

 

*Certain prior-year amounts have beenreclassified to conform with the current year’s presentation.*

*(1)**            Excludesincome from discontinued operations in 2006, 2005 and 2004 and cumulativeeffects of changes in accounting principles in 2005 as discussed in more detailin Item 8. Financial Statementsand Supplementary Data.*

**Merchant Energy Business**

**Introduction**

Our merchant energy business integrateselectric generation assets with the marketing and risk management of energy andenergy-related commodities, allowing us to manage energy price risk overgeographic regions and time.

Constellation Energy Commodities Group, our wholesalemarketing, risk management, and trading operation, dispatches the energy fromour generating facilities and from some facilities with which we have powerpurchase agreements, manages the risks associated with selling the output andpurchasing non-nuclear fuels, and enters into transactions to meet customers’energy and risk management requirements. This operation also trades energy andenergy-related commodities and deploys risk capital in the management ofour portfolio in order to earn additional returns. Constellation NewEnergy, ourelectric and gas retail operation, provides electricity, natural gas,transportation, and other energy services to commercial, industrial, andgovernmental customers.

Constellation Generation Group, our merchantgeneration operation, oversees the ownership, operations, maintenance, andperformance of our fossil, nuclear and renewable generation and fuel processingfacilities. Our generation capacity supports our wholesale and retailoperations by providing a source of reliable power supply. ConstellationGeneration Group also owns and operates a generation operations and maintenanceservices organization.

Our merchantenergy business:

 ̈  providedapproximately 34,650 megawatts (MW) of peak load in the aggregate to distributionutilities, municipalities, commercial, industrial, and governmental customersduring 2006,

 ̈  providedapproximately 355,000 million British Thermal Units (mmBTUs) of naturalgas to commercial, industrial, and governmental customers during 2006,

 ̈  delivered26.0 million tons of coal to international and domestic third-partycustomers and to our own fleet during 2006, and

 ̈  managedapproximately 8,680 MW of generation capacity as of December 31, 2006.

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

 ̈  Mid-AtlanticRegion—our fossil, nuclear, and hydroelectric generating facilities andload-serving activities in the PJM Interconnection (PJM) region. This alsoincludes active portfolio management of generating assets and other physicaland financial contractual arrangements, as well as other PJM competitive supplyactivities. In addition, due to the expiration of its power purchase agreement,beginning in June 2006 until its sale in December 2006, the resultsof our University Park generating facility are included with the Mid-AtlanticRegion. University Park was previously included in Plants with Power PurchaseAgreements.

 ̈  Plantswith Power Purchase Agreements—our generating facilities outside theMid-Atlantic Region with long-term power purchase agreements. As discussed in *Note 2**to Consolidated FinancialStatements*, the**sale of theHigh Desert facility resulted in a reclassification of its results todiscontinued operations.

 ̈  WholesaleCompetitive Supply—our marketing, risk management, and trading operation thatprovides energy products and services primarily to distribution utilities,power generators, and other wholesale customers. We also provide global energyand related services and upstream and downstream natural gas services.

 ̈  RetailCompetitive Supply—our operation that provides electric and natural gas energyproducts and services to commercial, industrial, and governmental customers.

 ̈  Other—our investments inqualifying facilities and domestic power projects and our generation operationsand maintenance services.

In December 2006, we completed the saleof the following gas-fired plants owned by our merchant energy business:
| **Facility**    | ** ** | ** ** | ** ** | **Capacity  (MW)** | ** ** | **Unit Type** | ** ** | **Location**  | ** ** |
|-----------------|------------|------------|------------|--------------------|------------|--------------------|------------|---------------|------------|
| High Desert     |       |       | 830        |               |       | Combined Cycle     |       | California    |       |
| Rio Nogales     |       |       | 800        |               |       | Combined Cycle     |       | Texas         |       |
| Holland         |       |       | 665        |               |       | Combined Cycle     |       | Illinois      |       |
| University Park |       |       | 300        |               |       | Peaking            |       | Illinois      |       |
| Big Sandy       |       |       | 300        |               |       | Peaking            |       | West Virginia |       |
| Wolf Hills      |       |       | 250        |               |       | Peaking            |       | Virginia      |       |

 

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We discuss the sale of thesegas-fired generating facilities in *Note 2 to ConsolidatedFinancial Statements*.

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

**Mid-Atlantic Region**

We own 6,305 MWof fossil, nuclear, and hydroelectric generation capacity in the Mid-AtlanticRegion. The output of these plants is managed by our wholesale marketing, riskmanagement, and trading operation and is hedged through a combination of powersales to wholesale and retail market participants. Our merchant energy businessmeets the load-serving requirements of various contracts using the output fromthe Mid-Atlantic Region and from purchases in the wholesale market.

BGE transferredall of these facilities to our merchant energy generation subsidiaries on July 1,2000 as a result of the implementation of electric customer choice andcompetition among suppliers in Maryland, except for the Handsome Lake facilitythat commenced operations in mid-2001. The assets transferred from BGEare subject to the lien of BGE’s mortgage.

Our merchant energy business supplies BGE with a portion of itsmarket-based standard offer service obligation. For 2006, the peak loadsupplied to BGE was approximately 3,490 MW.

**Plants with PowerPurchase Agreements**

We own 2,134 MWof nuclear generation capacity with power purchase agreements for a significantportion of their output. Our facilities with power purchase agreements are theNine Mile Point Nuclear Station (Nine Mile Point) and the R.E. Ginna NuclearPlant (Ginna).

We own 100% ofNine Mile Point Unit 1 (620 MW) and 82% of Unit 2 (933 MW). The remaininginterest in Nine Mile Point Unit 2 is owned by the Long Island Power Authority.Unit 1 entered service in 1969 and Unit 2 in 1988. Nine Mile Point is locatedwithin the New York Independent System Operator (NYISO) region.

We sell 90% ofour share of Nine Mile Point’s output to the former owners of the plant at anaverage price of nearly $35 per megawatt-hour (MWH) under agreements thatterminate between 2009 and 2011. The agreements are unit contingent (if theoutput is not available because the plant is not operating, there is norequirement to provide output from other sources). The remaining 10% of NineMile Point’s output is managed by our wholesale marketing, risk management, andtrading operation and sold into the wholesale market.

Aftertermination of the power purchase agreements, a revenue sharing agreement withthe former owners of the plant will begin and continue through 2021. Under thisagreement, which applies only to our ownership percentage of Unit 2, apredetermined price is compared to the market price for electricity. If themarket price exceeds the strike price, then 80% of this excess amount is sharedwith the former owners of the plant. The average strike price for the firstyear of the revenue sharing agreement is $40.75 per MWH. The strike priceincreases two percent annually beginning in the second year of the revenuesharing agreement. The revenue sharing agreement is unit contingent and isbased on the operation of the unit.

We exclusivelyoperate Unit 2 under an operating agreement with the Long Island PowerAuthority. The Long Island Power Authority is responsible for 18% of theoperating costs (and decommissioning costs) of Unit 2 and has representation onthe Nine Mile Point Unit 2 management committee which provides certainoversight and review functions.

In October 2006,we received Nuclear Regulatory Commission (NRC) approval for license extensionfor both units at our Nine Mile Point nuclear facility. With the renewedlicenses, we can continue to operate Unit 1 until 2029 and Unit 2 until 2046.

We own 100% of the Ginna nuclear facility. Ginna consists of a 581 MWreactor that entered service in 1970 and is licensed to operate until 2029. Wesell up to 90% of the plant’s output and capacity to the former owners for10 years at an average price of $44.00 per MWH under a long term unitcontingent power purchase agreement. The remaining output is managed by ourwholesale marketing, risk management, and trading operation and sold into thewholesale market. During the fourth quarter of 2006, we completed a plannedoutage at our Ginna nuclear facility, which included increasing the capacity ofthe plant from 498 MW to the current 581 MW. Based on the new capacity,beginning in 2007, we will sell approximately 80% of Ginna’s output to theformer owners.

**Competitive Supply**

We are a leading supplier of energy products and services to wholesalecustomers and retail commercial, industrial, and governmental customers. In2006, our wholesale marketing, risk management, and trading operation providedapproximately 17,950 peak MWs of wholesale full requirements load-servingproducts. During 2006, our retail competitive supply activities servedapproximately 16,700 MW of peak load and approximately 355,000 mmBTUs ofnatural gas.

***Wholesale andRetail Load-Serving Activities***

Our wholesalemarketing, risk management, and trading operation structures transactions thatserve the full energy and capacity requirements of various customers outsidethe PJM region such as distribution utilities, municipalities, cooperatives,and retail aggregators that do not own sufficient generating capacity orin-house supply functions to meet their own load requirements. 

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Our retailcompetitive supply operation structures transactions to supply full energy andcapacity requirements and provide natural gas, transportation, and other energyproducts and services to retail, commercial, industrial, and governmentalcustomers.

Contracts with these customers generally extend from one to ten years,but some can be longer. To meet our customers’ load-serving requirements, ourmerchant energy business obtains energy from various sources, including:

 ̈  bilateralpower and natural gas purchase agreements with third parties,

 ̈  unitcontingent purchases from generation companies,

 ̈  ourgeneration assets,

 ̈  regionalpower pools,

 ̈  tollingcontracts with generation companies, which provide us the right, but not theobligation, to purchase power at a price linked to the variable cost ofproduction, including fuel, with terms that generally extend from several monthsto several years, but can be longer, and

 ̈  exchangetraded electricity and natural gas contracts.

***PortfolioManagement and Trading***

We continue toidentify and pursue opportunities which can generate additional returns throughportfolio management and trading activities within our business. Theseopportunities have increased due to the significant growth in scale of ourcompetitive supply operations. In managing our portfolio, we may terminate,restructure, or acquire contracts. Such transactions are within the normalcourse of managing our portfolio and may materially impact the timing of ourrecognition of revenues, fuel and purchased energy expenses, and cash flows.

Our wholesalemarketing, risk management, and trading operation actively uses energy andenergy-related commodities in order to manage our portfolio of energypurchases and sales to customers through structured transactions. We use bothderivative and nonderivative contracts in managing our portfolio of energysales and purchase contracts. Generally, we expect to use both derivative andnonderivative contracts to hedge a majority of our portfolio over a three-yearperiod in order to reduce volatility in our results. Although a substantialportion of our portfolio is hedged, we are able to identify opportunities todeploy risk capital to increase the value of our accrual positions, which wecharacterize as portfolio management.

We trade energyand energy-related commodities and deploy risk capital in the managementof our portfolio in order to earn additional returns. These activities aremanaged through daily value at risk and stop loss limits and liquidityguidelines, and could have a material impact on our financial results. Wediscuss the impact of our trading activities and value at risk in more detailin *Item 7. Management’s Discussion andAnalysis.*

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

 ̈  forwardcontracts (which commit us to purchase or sell energy commodities in thefuture),

 ̈  swapagreements (which require payments to or from counterparties based upon thedifference between two prices for a predetermined contractual (notional)quantity),

 ̈  optioncontracts (which convey the right to buy or sell a commodity, financialinstrument, or index at a predetermined price), and

 ̈  futurescontracts (which are exchange traded standardized commitments to purchase orsell a commodity or financial instrument, or make a cash settlement, at aspecified price and future date).

Active portfolio management allows our wholesale marketing, riskmanagement, and trading operation to:

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

 ̈  providefixed-price energy commitments to customers and suppliers,

 ̈  reduceexposure to the volatility of market prices, and

 ̈  hedgefuel requirements at our non-nuclear generation facilities.

***Coal andInternational Services***

Our wholesalemarketing, risk management, and trading operation participates in global coalsourcing activities by providing coal and coal-related logistical services, forthe variable or fixed supply needs of global customers. In 2006, we delivered26.0 million tons of coal to global customers and to our own fleet.Additionally, we entered into power,natural gas, freight, and emissions transactions outside of the United States.We also include in our coal services the results from our synthetic fuelprocessing facility in South Carolina.

We will continue to evaluate new international opportunities, includingexpanding our coal sourcing, freight, and power, natural gas and emissionsactivities outside of the United States.

***Natural GasServices***

Our wholesalemarketing, risk management, and trading operation includes upstream(exploration and production) and downstream (transportation and storage)natural gas operations. Our upstream activities include the acquisition,development, and exploitation of natural gas properties. Our downstreamactivities include providing natural gas to various customers, including largeutilities, industrial customers, power generators, wholesale marketers, andretail aggregators.

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In 2006and 2005, we acquired working interests in gas producing fields. We discussthese acquisitions in more detail in *Note 15to Consolidated Financial Statements*.

In November 2006, we completed the initial public offering ofConstellation Energy Partners LLC (CEP), a limited liability company that weformed. CEP is principally engaged in the acquisition, development, andexploitation of natural gas properties. CEP’s existing property is located inthe Robinson’s Bend Field in the Black Warrior Basin of Alabama. We continue to own 54% of CEP and as aresult, we continue to consolidate CEP. We discuss the impact of thisinitial public offering on our financial results in more detail in *Note 2 to Consolidated Financial Statements*.

**Other**

We hold up to a50% voting interest in 24 operating energy projects that consist of electricgeneration (primarily relying on alternative fuel sources), fuel processing, orfuel handling facilities. These generating projects are considered qualifyingfacilities under the Public Utility Regulatory Policies Act of 1978. Eachelectric generating plant sells its output to a local utility under long-termcontracts.

We also provide operation and maintenance services, including testingand start-up, to owners of electric generating facilities.

**UniStar Nuclear**

In 2005, weformed UniStar Nuclear, LLC (UniStar), a joint enterprise with AREVA NP, Inc.,to develop the business model for a standardized fleet of nuclear power plantsbased on an advanced design called the U.S. Evolutionary Power Reactor (U.S.EPR). UniStar provides the framework through which we can work with AREVA NP, Inc.to obtain design certification and all necessary approvals from the NRC tolicense, construct, own, and operate U.S. EPR plants. 

UniStar alsooffers the business framework that could enable the development of future jointventures with Constellation Energy, other energy companies, and interestedparties. Those future joint ventures, in turn, would license, construct, own,and operate nuclear power plants as part of a standardized fleet. However,prior to identifying specific projects or committing to ordering new nuclearpower plants, our financial commitment will be limited to the formation of thebusiness platform and business development activities, including licensing andpermit activities and securing access to long-lead materials such as heavyforgings needed for reactor pressure vessels and steam generators or turbineand generator parts.

**Fuel Sources**

Our power plants use diverse fuel sources. Our fuel mix based oncapacity owned at December 31, 2006 and our generation based on actualoutput by fuel type in 2006 were as follows:
| **Fuel**                                                                      | ** ** | ** ** | ** ** | **Capacity Owned** | ** ** | **Generation*** | ** ** |
|-------------------------------------------------------------------------------|------------|------------|------------|-------------------------|------------|-----------------|------------|
| Nuclear                                                                       |       |       | 45         | %                       |       |            | 52         | % |   |
| Coal                                                                          |       |       | 32         |                    |       |            | 30         |   |   |
| Natural Gas                                                                   |       |       | 7          |                    |       |            | 15         |   |   |
| Oil                                                                           |       |       | 8          |                    |       |            | —     |   |   |
| Renewable and  Alternative (1)        |       |       | 5          |                    |       |            | 3          |   |   |
| Dual (2)                                                                 |       |       | 3          |                    |       |            | —     |   |   |

 

****                      Includesoutput from gas-fired plants until sale in December 2006.*

*(1)**            Includessolar, geothermal, hydro, waste coal and biomass.*

*(2)**            Switchesbetween natural gas and oil.*

We discuss our risks associated with fuel in more detail in *Item 7. Management’s Discussion and Analysis—MarketRisk.*

***Nuclear***

The output at our nuclear facilities over thepast five years (including periods prior to our acquisition of Ginna in June 2004)is presented in the following table:
| ** ** | ** ** | **Calvert Cliffs**  | ** ** | **Nine Mile Point** | ** ** | **Ginna** | ** ** |
|------------|------------|--------------------------|------------|-------------------------------|------------|-----------|------------|
| ** ** | ** ** | **MWH**                  | ** ** | **Capacity  Factor**          | ** ** | **MWH***  | ** ** | **Capacity  Factor** | ** ** | **MWH** | ** ** | **Capacity  Factor** | ** ** |
| ** ** | ** ** | ***(MWH  in millions)*** | ** ** |
| 2006       |       |                     | 13.8       |                          |       |      | 90         | % |   |   | 12.8 |   |   |   | 93 | % |   |   | 4.1 |   |   |   | 93 | % |   |
| 2005       |       |                     | 14.7       |                          |       |      | 97         |   |   |   | 12.7 |   |   |   | 93 |   |   |   | 4.0 |   |   |   | 93 |   |   |
| 2004       |       |                     | 14.5       |                          |       |      | 96         |   |   |   | 12.1 |   |   |   | 89 |   |   |   | 4.3 |   |   |   | 100 |   |   |
| 2003       |       |                     | 13.7       |                          |       |      | 93         |   |   |   | 12.2 |   |   |   | 90 |   |   |   | 3.9 |   |   |   | 90 |   |   |
| 2002       |       |                     | 12.1       |                          |       |      | 82         |   |   |   | 11.7 |   |   |   | 87 |   |   |   | 3.8 |   |   |   | 89 |   |   |

 

****represents our proportionateownership interest*

The supply of fuel for nuclear generating stations includes the:

 ̈  purchaseof uranium (concentrates and uranium hexafluoride),

 ̈  conversionof uranium concentrates to uranium hexafluoride,

 ̈  enrichmentof uranium hexafluoride, and

 ̈  fabricationof nuclear fuel assemblies.
| Uranium and Conversion |   | We have commitments for sufficient  quantities of uranium (concentrates and uranium hexafluoride) to meet 100% of  our total requirements through 2010. Additionally, we have commitments  covering approximately 95% of our requirements in 2011. |
|------------------------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

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| Enrichment                |   | We have commitments that provide  100% of our uranium enrichment requirements through 2010 and 75% of these  requirements in 2011 and 2012. We have commitments that provide 50% of our  uranium enrichment requirements from 2013 through 2020. |
|---------------------------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Fuel Assembly Fabrication |   | We have commitments for the  fabrication of fuel assemblies for reloads required through 2013 for Nine  Mile Point and Calvert Cliffs Nuclear Power Plant, Inc. (Calvert  Cliffs), and through 2017 for Ginna.                              |

 

 

The nuclear fuel markets are competitive, and although prices for uraniumand conversion are increasing, we do not anticipate any significant problems inmeeting our future requirements.

*Storage ofSpent Nuclear Fuel—Federal Facilities*

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

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

The DOE hasstated that it may not meet that obligation until 2017 at the earliest. Thisdelay has required that we undertake additional actions to provide on-site fuelstorage at Calvert Cliffs, Ginna, and Nine Mile Point, including theinstallation of on-site dry fuel storage capacity at Calvert Cliffs, asdescribed in more detail below. In 2004, complaints were filed against thefederal government in the United States Court of Federal Claims seeking torecover damages caused by the DOE’s failure to meet its contractual obligationto begin disposing of spent nuclear fuel by January 31, 1998. These casesare currently stayed, pending litigation in other related cases.

In connectionwith our purchase of Ginna, all of the former owner’s rights and obligationsrelated to recovery of damages for DOE’s failure to meet its contractualobligations were assigned to us. However, we have an obligation to reimbursethe former owner for up to $10 million of any recovered damages for suchclaims.

*Storage of Spent Nuclear Fuel—On-SiteFacilities*

Calvert Cliffshas a license from the NRC to operate an on-site independent spent fuel storageinstallation that expires in 2012. We have storage capacity at Calvert Cliffsthat will accommodate spent fuel from operations through 2011. In addition, wecan expand our temporary storage capacity at Calvert Cliffs to meet futurerequirements until approximately 2025. Nine Mile Point and Ginna are beginning initialplanning studies for the potential development of independent spent fuelstorage capacity. Nine Mile Point’s Unit 1 has sufficient storage capacitywithin the plant until 2011. Nine Mile Point’s Unit 2 has sufficient storagecapacity within the plant until 2012. Ginna has sufficient storage capacitywithin the plant until 2010.

*Cost for Decommissioning Uranium EnrichmentFacilities*

The Energy PolicyAct of 1992 requires domestic nuclear utilities to contribute to a fund fordecommissioning and decontaminating uranium enrichment facilities that had beenoperated by DOE. These contributions are generally payable over a 15-yearperiod with escalation for inflation and are based upon the amount of uraniumenriched by DOE for each utility through 1992. The 1992 Act provides that thesecosts are recoverable through utility service rates. BGE is solely responsiblefor these costs as they relate to Calvert Cliffs and made the last payment in2006. The sellers of the Nine Mile Point plant and the Long Island PowerAuthority are responsible for the costs relating to the Nine Mile Point plant.The seller of Ginna is responsible for the costs related to that facility.

*Cost for Decommissioning*

We are obligated to decommission our nuclearplants at the time these plants cease operation. Every two years, the NRCrequires us to demonstrate reasonable assurance that funds will be available todecommission the sites. When BGE transferred all of its nuclear generatingassets to our merchant energy business, it also transferred the trust fundestablished to pay for decommissioning Calvert Cliffs. At December 31,2006, the Calvert Cliffs trust fund assets were $420.6 million.

Under the Maryland Public Service Commission’s(Maryland PSC) order regarding the deregulation of electric generation, BGEratepayers must pay a total of $520 million, in 1993 dollars adjusted forinflation, to decommission Calvert Cliffs through fixed annual collections. In2006, BGE received approval from the Maryland PSC to continue annual customercollections of approximately $18.7 million through December 31, 2016.BGE will be required to submit a filing to determine the level of customercontributions after December 31, 2016. 

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BGE iscollecting this amount on behalf of Calvert Cliffs. Any costs to decommissionCalvert Cliffs in excess of this $520 million must be paid by CalvertCliffs. If BGE ratepayers have paid more than this amount at the time ofdecommissioning, Calvert Cliffs must refund the excess. If the cost todecommission Calvert Cliffs is less than the $520 million BGE’s ratepayersare obligated to pay, Calvert Cliffs may keep the difference.

As discussed in*Baltimore Gas and Electric Company—Provider of Last Resort*section, Senate Bill 1, which was enactedin June 2006, requires BGE to provide credits to residential electriccustomers equal to the amount collected for decommissioning annually for10 years beginning January 1, 2007. Under the provisions of SenateBill 1 we are required to apply the collection of the nuclear decommissioningtrust funds over the ten year period beginning January 1, 2007 toward the fulfillmentof the decommissioning obligations of BGE ratepayers.

The sellers ofNine Mile Point transferred a $441.7 million decommissioning trust fund tous at the time of sale. In return, we assumed all liability for the costs todecommission Unit 1 and 82% of the costs to decommission Unit 2. We believethat this amount is adequate to cover our responsibility for decommissioningNine Mile Point to a greenfield status (restoration of the site so that itsubstantially matches the natural state of the surrounding properties and thesite’s intended use). At December 31, 2006, the Nine Mile Point trust fundassets were $572.8 million.

The seller ofGinna transferred $200.8 million in decommissioning funds to us. Inreturn, we assumed all liability for the costs to decommission the unit. Webelieve that this amount will be sufficient to cover our responsibility fordecommissioning Ginna to a greenfield status. At December 31, 2006, theGinna trust fund assets were $246.7 million.

***Coal***

We purchase themajority of our coal for electric generation under supply contracts with miningoperators, and we acquire the remainder in the spot or forward coal markets. Webelieve that we will be able to renew supply contracts as they expire or enterinto contracts with other coal suppliers. Our primary coal burning facilitieshave the following requirements:
|                              | ** ** | **Approximate  Annual Coal  Requirement  (tons)** | ** ** | **Special Coal  Restrictions** |
|------------------------------|------------|---------------------------------------------------|------------|--------------------------------|
| Brandon Shores Units 1 and 2 |       |                                              | 3,500,000  |                           |   | Sulfur content less than 1.20 lbs  per |
| (combined)                   |       |                                              |       |                           |   | mmBTU |
| C. P. Crane   Units 1 and 2  |       |                                              | 850,000    |                           |   | Low ash melting temperature |
| (combined)                   |       |                                              |       |                           |   |   |
| H. A. Wagner  Units 2 and 3  |       |                                              | 1,100,000  |                           |   | Sulfur content no  more than 1% |
| (combined)                   |       |                                              |       |                           |   |   |

Coal deliveries to these facilities are made by rail and barge. Overthe past few years, we expanded our coal sources including restructuring ourrail contracts, increasing the range of coals we can consume, adding syntheticfuel as an alternate source, and finding potential other coal supply sourcesincluding shipments from various international sources. While we primarily usecoal produced from mines located in central and northern Appalachia, we arecapable of switching to imported coals to manage our coal supply. The timelydelivery of coal together with the maintenance of appropriate levels ofinventory is necessary to allow for continued, reliable generation from thesefacilities.

All of theConemaugh and Keystone plants’ annual coal requirements are purchased by theplant operators from regional suppliers on the open market. The sulfurrestrictions on coal are approximately 2.3% for the Keystone plant andapproximately 5.3% for the Conemaugh plant.

The annual coalrequirements for the ACE, Jasmin, and Poso plants, which are located inCalifornia, are supplied under contracts with mining operators. The Jasmin andPoso plants are restricted to coal with sulfur content less than 4.0% and ACEis restricted to less than 2.0%.

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

***Gas***

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

***Oil***

Under normal burn practices, our requirements for residual fuel oil (No. 6)amount to approximately 1.5 million to 2.0 million barrels oflow-sulfur oil per year. Deliveries of residual fuel oil are made from thesuppliers’ Baltimore Harbor and Philadelphia marine terminals for distributionto the various generating plant locations. Also, based on normal burn practices,we require approximately 8.0 million to 11.0 million gallons ofdistillates (No. 2 oil and kerosene) annually, but these requirements canvary substantially from year 

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to year depending upon the relationship between energy prices and fuelcosts, weather conditions, and operating requirements. Distillates arepurchased from the suppliers’ Baltimore truck terminals for distribution to thevarious generating plant locations. We have contracts with various suppliers topurchase oil at spot prices, and for future delivery, to meet our requirements.

**Competition**

Marketdevelopments over the past several years have changed the nature of competitionin the merchant energy business. Certain companies within the merchant energysector have curtailed their activities or withdrawn completely from thebusiness. However, new competitors (e.g., financial investors, banks andinvestment banks) have entered the market. We encounter competition fromcompanies of various sizes, having varying levels of experience, financial andhuman resources, and differing strategies.

We facecompetition in the market for energy, capacity, and ancillary services. In ourmerchant energy business, we compete with international, national, and regionalfull service energy providers, merchants, and producers to obtain competitivelypriced supplies from a variety of sources and locations, and to utilizeefficient transmission, transportation, or storage. We principally compete onthe basis of price, customer service, reliability, and availability of ourproducts.

With respect topower generation, we compete in the operation of energy-producingprojects, and our competitors in this business are both domestic andinternational organizations, including various utilities, industrial companiesand independent power producers (including affiliates of utilities, financialinvestors, banks and investment banks), some of which have greater financialresources.

States areconsidering different types of regulatory initiatives concerning competition inthe power industry, which makes a competitive assessment difficult. Increasedcompetition that resulted from some of these initiatives in several statescontributed in some instances to a reduction in electricity prices and putpressure on electric utilities to lower their costs, including the cost ofpurchased electricity. While many states continue to support retail competitionand industry restructuring, other states that were considering deregulationhave slowed their plans or postponed consideration of deregulation. Inaddition, other states are reconsidering deregulation.

We believethere is adequate growth potential in the current deregulated market and thatfurther market changes could provide additional opportunities for our merchantenergy business. In addition, our wholesale marketing, risk management, andtrading operation participates in global coal sourcing activities by providingcoal for the variable or fixed supply needs of North American and internationalpower generators. In addition, our wholesale marketing, risk management, andtrading operation includes upstream (exploitation and production) anddownstream (transportation and storage) natural gas operations.

As the market for commercial, industrial, and governmental supplycontinues to grow, we have experienced increased competition on a regionalbasis in our retail competitive supply activities. The increase in retailcompetition and the impact of wholesale power prices compared to the ratescharged by local utilities has, in certain circumstances, reduced the marginsthat we realize from our customers. However, we believe that our experience andexpertise in assessing and managing risk and our strong focus on customerservice will help us to remain competitive during volatile or otherwise adversemarket circumstances.

**MerchantEnergy Operating Statistics**
| ** **                             | ** ** | **2006**    | ** **   | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|----------------------------------------|------------|-------------|--------------|----------|------------|----------|------------|----------|------------|----------|------------|
| Revenues*(In millions)*                | ** ** | ** **  |         |     |       |     |       |     |       |     |       |
| Mid-Atlantic  Region                   | ** ** | **$**       | **2,813.5**  |     | $          | 2,283.9  |       | $        | 1,925.6    |     | $          | 1,696.2 |   | $ | 1,415.1 |   |
| Plants with  Power Purchase Agreements | ** ** | **650.5**   |         | 665.9    |       | 555.3    |       | 463.3    |       | 433.2    |       |
| Competitive  Supply—Retail        | ** ** | **8,014.7** |         | 6,942.3  |       | 4,280.0  |       | 2,567.7  |       | 312.7    |       |
| Competitive  Supply—Wholesale     | ** ** | **5,612.7** |         | 4,672.3  |       | 3,353.8  |       | 2,703.9  |       | 540.7    |       |
| Other                                  | ** ** | **74.8**    |         | 58.0     |       | 73.6     |       | 45.1     |       | 56.4     |       |
| Total Revenues                         | ** ** | **$**       | **17,166.2** |     | $          | 14,622.4 |       | $        | 10,188.3   |     | $          | 7,476.2 |   | $ | 2,758.1 |   |
| Generation*(In millions)—*MWH*    | ** ** | **59.1**    |         | 60.2     |       | 55.3     |       | 51.6     |       | 44.7     |       |

** Includes output from gas-fired plants untilsale in December 2006.*

*Operatingstatistics do not reflect the elimination of intercompany transactions.*

*Certain prior-yearamounts have been reclassified to conform with the current year’s presentation.The reclassifications primarily relate to operations that have been reflectedas discontinued in the current year.*

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**Baltimore Gas andElectric Company**

BGE is an electric transmissionand distribution utility company and a gas distribution utility company with aservice territory that covers the City of Baltimore and all or part of tencounties in central Maryland. BGE is regulated by the Maryland PSC and FederalEnergy Regulatory Commission (FERC) with respect to rates and other aspects ofits business.

BGE’s electric service territoryincludes an area of approximately 2,300 square miles. There are no municipal orcooperative wholesale customers within BGE’s service territory. BGE’s gasservice territory includes an area of approximately 800 square miles.

BGE’s electric and gas revenues come from many customers—residential,commercial, and industrial.

**Electric Business**

***Electric Regulatory Matters and Competition***

*Deregulation*

Effective July 1, 2000, electric customer choice and competitionamong electric suppliers was implemented in Maryland. As a result of thederegulation of electric generation, all customers can choose their electricenergy supplier. While BGE does not sell electric commodity to all customers inits service territory, BGE continues to deliver electricity to all customersand provides meter reading, billing, emergency response, and regularmaintenance.

*Standard OfferService*

BGE providedfixed-price standard offer service to commercial and industrial customersthrough either June 30, 2002 or June 30, 2004, depending on customertype, and for residential customers through June 30, 2006.

Upon the expiration of fixed-price standard offer service, customersthat continue to receive their electric supply from BGE are charged market-basedstandard offer service rates (Provider of Last Resort rates). We discussProvider of Last Resort (POLR) rates in more detail below.

*Provider ofLast Resort*

BGE isobligated to provide market-based standard offer service to all of its electriccustomers for varying periods. The POLR rates charged recover BGE’s wholesalepower supply costs and include an administrative fee. The administrative feeincludes a shareholder return component and an incremental cost component. As aresult of Senate Bill 1, beginning January 1, 2007, the shareholder returncomponent of the administrative charge for residential POLR service wassuspended. We discuss Senate Bill 1 in detail in the *ResidentialCustomers*section.

Bidding to supply BGE’s market-based standard offer service willoccur from time to time through a competitive bidding process approved by theMaryland PSC. Successful bidders, which may include subsidiaries ofConstellation Energy, will execute contracts with BGE for varying terms.

*Commercial andIndustrial Customers*

BGE isobligated to provide market-based standard offer service to commercialand industrial customers for varying periods beyond June 30, 2004,depending on customer load.

In August 2006,the Maryland PSC issued an order indefinitely extending the obligation ofMaryland utilities to provide POLR service for those commercial and industrialcustomers for which market-based standard offer service was scheduled to expireat the end of May 2007. The extended service will be provided onsubstantially the same terms as under the existing service, except thatwholesale bidding for service to some customers will be conducted morefrequently.

BGE’s obligation to provide market-based standard offer serviceto its largest commercial and industrial customers expired on May 31,2005. BGE continues to provide an hourly-priced market-basedstandard offer service to those customers.

*ResidentialCustomers*

As a result ofthe November 1999 Maryland PSC order regarding the deregulation ofelectric generation in Maryland, BGE’s residential electric base rates werefrozen until July 2006. Subsequent orders of the Maryland PSC specifiedthat BGE would procure the power to serve residential customers beginning July 2006via auctions to be conducted in late 2005 and early 2006. The procured powercosts of these auctions would have resulted in an average electric residentialcustomer bill increase of 72%. In June 2006, Senate Bill 1 wasenacted, which, among other things:

 ̈  imposesrate stabilization measures that (i) cap rate increases by BGE forresidential POLR service at 15% from July 1, 2006 to May 31, 2007, (ii) giveresidential POLR customers the option from June 1, 2007 until December 31,2007 of paying a full market rate or choosing a short term rate stabilizationplan in order to provide a smooth transition to market rates without adverselyaffecting the creditworthiness of BGE, and (iii) provide for full marketrates for residential POLR service starting January 1, 2008;

 ̈  allowsBGE to recover the costs deferred from July 1, 2006 to May 31, 2007from its customers over a period not to exceed 10 years, on terms andconditions to be determined by the Maryland PSC, including through the issuanceof rate stabilization bonds that securitize the deferred costs;

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 ̈  directs the Maryland PSC toinvestigate measures to mitigate the impact of residential rate increases onBGE customers, including by investigating the prior determination of andallowances for stranded costs that occurred when BGE transferred assets to itsaffiliates in 2000 and by requiring the Maryland PSC to provide funds toresidential customers of BGE for mitigation of BGE’s rate increases, includingany adjustment in favor of BGE’s customers to allowances for such strandedcosts; and

 ̈  requires BGE to reduceresidential electric rates by approximately $39 million per year for10 years, beginning January 1, 2007, through suspension of thecollection of the residential return component of the administrative charge forPOLR service and a credit equal to the amount collected from BGE ratepayers forthe nuclear decommissioning trust for Calvert Cliffs. We provide furtherdetails in the C*ost for Decommissioning* section.

In August 2006, the Maryland PSC beganits investigation into the general regulatory structure, agreements, orders,and other prior actions of the Maryland PSC under the Electric Customer Choiceand Competition Act of 1999, including the determination of and allowances forstranded costs. We cannot predict the outcome of the investigation, but itcould have a material adverse effect on our, or BGE’s, financial results. 

In December 2006, the Maryland PSCissued an order that allows BGE to securitize its costs relating to theresidential rate deferral through the issuance of bonds in an aggregateprincipal amount of approximately $630 million, subject to adjustment.

Also in December 2006, in connectionwith implementing the $39 million in annual residential electric ratereductions discussed above, BGE and Calvert Cliffs notified the Maryland PSCthat they had entered into a standstill agreement with the Attorney General ofthe State of Maryland with respect to potential challenges to the provisions ofSenate Bill 1 relating to the reductions.

In January 2007, BGE filed a proposedplan with the Maryland PSC that would allow residential electric customers todefer the transition to full market rates from June 1, 2007 toDecember 31, 2007. Under the proposed plan, electric rates for residentialcustomers who elect this extended deferral would increase on June 1, 2007 byone-half of the total increase remaining to reach full market rates on January1, 2008. We estimate that electric rates for residential electric customersunder this plan will be approximately 20-25% higher on June 1, 2007 compared tocurrent residential electric rates. This estimate may differ from the actualincrease on June 1, 2007 based on BGE's actual procured power cost, which willbe determined in April 2007 via auctions. Customers who choose to defer wouldrepay the deferred amounts over a two-year period starting January 1, 2008,at which time these customers would transition to full market rates. Theproposed plan remains subject to Maryland PSC approval.

Because Senate Bill 1 requires additionaldecisions and proceedings by the Maryland PSC and other governmental authoritiesto implement and interpret many of its provisions, we cannot predict theultimate impact of the legislation on us, BGE, or the energy market inMaryland. The new legislation and its implementation through applicableregulatory proceedings could have a material adverse effect on our, or BGE’s,financial results. In addition, one or more parties may challenge in court oneor more provisions of Senate Bill 1. The outcome of any challenges and theuncertainty that could result cannot be predicted.

We discussother aspects of Senate Bill 1 in *Item 7. Management’sDiscussion and Analysis—Business Environment—Senate Bill 1* section. Wediscuss the market risk of our regulated electric business in more detail in *Item 7. Management’s Discussion and Analysis—Market Risk*section.

***Electric Load Management***

BGE hasimplemented various programs for use when system-operating conditions ormarket economics indicate that a reduction in load would be beneficial. Werefer to these programs as active load management programs. These programsinclude:

 ̈  twooptions for commercial and industrial customers to voluntarily reduce theirelectric loads,

 ̈  airconditioning control for residential and commercial customers, and

 ̈  residentialwater heater control.

These programsgenerally take effect on summer days when demand and/or wholesale prices arerelatively high and had the capability during the 2006 summer to reduce load upto approximately 233 MW.

***Transmission and Distribution Facilities***

BGE maintains approximately 250 substationsand 1,300 circuit miles of transmission lines throughout central Maryland. BGEalso maintains approximately 23,900 circuit miles of distribution lines. Thetransmission facilities are connected to those of neighboring utility systemsas part of PJM. Under the PJM Tariff and various agreements, BGE and othermarket participants can use regional transmission facilities for energy,capacity, and ancillary services transactions including emergency assistance.

We discuss various FERC initiatives relatingto wholesale electric markets in more detail in *Item 7. Management’s Discussion and Analysis—Federal Regulation*section.

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**ElectricOperating Statistics**
| ** **                                       | ** ** | **2006**    | ** **  | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|--------------------------------------------------|------------|-------------|-------------|----------|------------|----------|------------|----------|------------|----------|------------|
| Revenues *(In millions)*                         |       |        |        |     |       |     |       |     |       |     |       |
| Residential                                      | ** ** | **$**       | **1,092.1** |     | $          | 1,066.6  |       | $        | 1,015.8    |     | $          | 959.0 |   | $ | 946.6 |   |
| Commercial                                       |       |        |        |     |       |     |       |     |       |     |       |
| Excluding Delivery Service Only                  | ** ** | **733.4**   |        | 722.1    |       | 708.9    |       | 694.2    |       | 776.0    |       |
| Delivery Service Only                            | ** ** | **149.4**   |        | 107.5    |       | 78.6     |       | 66.1     |       | 33.5     |       |
| Industrial                                       |       |        |        |     |       |     |       |     |       |     |       |
| Excluding Delivery Service Only                  | ** ** | **46.8**    |        | 52.8     |       | 92.3     |       | 137.0    |       | 158.7    |       |
| Delivery Service Only                            | ** ** | **26.2**    |        | 28.0     |       | 21.3     |       | 18.2     |       | 10.9     |       |
| System Sales and Deliveries                      | ** ** | **2,047.9** |        | 1,977.0  |       | 1,916.9  |       | 1,874.5  |       | 1,925.7  |       |
| Other (A)                                   | ** ** | **68.0**    |        | 59.5     |       | 50.8     |       | 47.1     |       | 40.3     |       |
| Total                                            | ** ** | **$**       | **2,115.9** |     | $          | 2,036.5  |       | $        | 1,967.7    |     | $          | 1,921.6 |   | $ | 1,966.0 |   |
| Distribution  Volumes *(In  thousands)*—MWH |       |        |        |     |       |     |       |     |       |     |       |
| Residential                                      | ** ** | **12,886**  |        | 13,762   |       | 13,313   |       | 12,754   |       | 12,652   |       |
| Commercial                                       |       |        |        |     |       |     |       |     |       |     |       |
| Excluding Delivery Service Only                  | ** ** | **6,325**   |        | 7,847    |       | 9,286    |       | 9,937    |       | 11,840   |       |
| Delivery Service Only                            | ** ** | **9,392**   |        | 7,967    |       | 5,767    |       | 4,982    |       | 2,762    |       |
| Industrial                                       |       |        |        |     |       |     |       |     |       |     |       |
| Excluding Delivery Service Only                  | ** ** | **467**     |        | 614      |       | 1,429    |       | 2,556    |       | 3,478    |       |
| Delivery Service Only                            | ** ** | **2,988**   |        | 3,122    |       | 2,562    |       | 1,780    |       | 997      |       |
| Total                                            | ** ** | **32,058**  |        | 33,312   |       | 32,357   |       | 32,009   |       | 31,729   |       |
| Customers *(In thousands)*                       |       |        |        |     |       |     |       |     |       |     |       |
| Residential                                      | ** ** | **1,093.3** |        | 1,084.1  |       | 1,072.1  |       | 1,061.7  |       | 1,052.3  |       |
| Commercial                                       | ** ** | **115.5**   |        | 114.7    |       | 113.6    |       | 112.1    |       | 110.8    |       |
| Industrial                                       | ** ** | **5.2**     |        | 5.0      |       | 4.8      |       | 4.9      |       | 4.9      |       |
| Total                                            | ** ** | **1,214.0** |        | 1,203.8  |       | 1,190.5  |       | 1,178.7  |       | 1,168.0  |       |

 

(A)           Primarily includesnetwork integration transmission service revenues, late payment charges,miscellaneous service fees, and tower leasing revenues.

*Operatingstatistics do not reflect the elimination of intercompany transactions.*

*“Delivery service only” refers to BGE’sdelivery of commodity that was purchased by the customer from an alternatesupplier.*

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**Gas Business**

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

BGE also provides customers withmeter reading, billing, emergency response, regular maintenance, and balancingservices.

Approximately 50% of the gasdelivered on BGE’s distribution system is for customers that purchase gas fromalternative suppliers. These customers are charged fees to recover the costsBGE incurs to deliver the customers’ gas through our distribution system.

In December 2005, theMaryland PSC issued an order granting BGE a $35.6 million annual increase inits gas base rates. In December 2006, the Baltimore City Circuit Courtupheld the rate order. However, certain parties have filed an appeal with theCourt of Special Appeals. We cannot provide assurance that the Maryland PSC’sorder will not be reversed in whole or in part or that certain issues will notbe remanded to the Maryland PSC for reconsideration.

For customers that buy their gasfrom BGE, there is a market-based rates incentive mechanism. Under thismarket-based rates incentive mechanism, our actual cost of gas iscompared to a market index (a measure of the market price of gas in a givenperiod). The difference between our actual cost and the market index is sharedequally between shareholders and customers. BGE must secure fixed-pricecontracts for at least 10%, but not more than 20%, of forecasted system supplyrequirements for the November through March period. These fixed-pricecontracts are not subject to sharing under the market-based ratesincentive mechanism.

BGE purchases the natural gas itresells to customers directly from many producers and marketers. BGE hastransportation and storage agreements that expire from 2007 to 2028.

BGE’s current pipeline firmtransportation entitlements to serve BGE’s firm loads are 313,053 dekatherms(DTH) per day.

BGE’s current maximum storageentitlements are 235,080 DTH per day. To supplement its gas supply at times ofheavy winter demands and to be available in temporary emergencies affecting gassupply, BGE has:

 ̈  aliquefied natural gas facility for the liquefaction and storage of natural gaswith a total storage capacity of 1,092,977 DTH and a daily capacity of 311,500DTH, and

 ̈  apropane air facility with a mined cavern with a total storage capacityequivalent to 564,200 DTH and a daily capacity of 85,000 DTH.

BGE has under contractsufficient volumes of propane for the operation of the propane air facility andis capable of liquefying sufficient volumes of natural gas during the summermonths for operations of its liquefied natural gas facility during peak winterperiods.

BGE historically has been ableto arrange short-term contracts or exchange agreements with other gas companiesin the event of short-term disruptions to gas supplies or to meet additionaldemand.

BGE also participates in theinterstate markets by releasing pipeline capacity or bundling pipeline capacitywith gas for off-system sales. Off-system gas sales are low-margin direct salesof gas to wholesale suppliers of natural gas. Earnings from these activitiesare shared between shareholders and customers. BGE makes these sales as part ofa program to balance our supply of, and cost of, natural gas.

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**GasOperating Statistics**
| ** **                                      | ** ** | **2006**    | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------------------|------------|-------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
| Revenues *(In millions)*                        |       |        |       |     |       |     |       |     |       |     |       |
| Residential                                     |       |        |       |     |       |     |       |     |       |     |       |
| Excluding Delivery Service Only                 | ** ** | **$**       | **490.2**  |     | $          | 558.5    |       | $        | 478.0      |     | $          | 444.5 |   | $ | 342.1 |   |
| Delivery Service Only                           | ** ** | **20.6**    |       | 23.2     |       | 14.2     |       | 13.6     |       | 16.5     |       |
| Commercial                                      |       |        |       |     |       |     |       |     |       |     |       |
| Excluding Delivery Service Only                 | ** ** | **148.9**   |       | 174.4    |       | 135.4    |       | 128.6    |       | 89.4     |       |
| Delivery Service Only                           | ** ** | **35.9**    |       | 31.9     |       | 28.0     |       | 24.6     |       | 29.2     |       |
| Industrial                                      |       |        |       |     |       |     |       |     |       |     |       |
| Excluding Delivery Service Only                 | ** ** | **7.5**     |       | 10.5     |       | 9.4      |       | 11.5     |       | 9.3      |       |
| Delivery Service Only                           | ** ** | **19.3**    |       | 12.4     |       | 7.8      |       | 11.4     |       | 13.9     |       |
| System Sales and Deliveries                     | ** ** | **722.4**   |       | 810.9    |       | 672.8    |       | 634.2    |       | 500.4    |       |
| Off-System Sales                                | ** ** | **168.6**   |       | 154.7    |       | 77.2     |       | 84.8     |       | 74.8     |       |
| Other                                           | ** ** | **8.5**     |       | 7.2      |       | 7.0      |       | 7.0      |       | 6.1      |       |
| Total                                           | ** ** | **$**       | **899.5**  |     | $          | 972.8    |       | $        | 757.0      |     | $          | 726.0 |   | $ | 581.3 |   |
| Distribution Volumes *(In  thousands)*—DTH |       |        |       |     |       |     |       |     |       |     |       |
| Residential                                     |       |        |       |     |       |     |       |     |       |     |       |
| Excluding Delivery Service Only                 | ** ** | **33,019**  |       | 39,107   |       | 39,080   |       | 40,894   |       | 35,364   |       |
| Delivery Service Only                           | ** ** | **3,948**   |       | 5,423    |       | 6,053    |       | 6,640    |       | 6,404    |       |
| Commercial                                      |       |        |       |     |       |     |       |     |       |     |       |
| Excluding Delivery Service Only                 | ** ** | **11,683**  |       | 14,133   |       | 13,248   |       | 13,895   |       | 11,583   |       |
| Delivery Service Only                           | ** ** | **25,695**  |       | 28,993   |       | 34,120   |       | 29,138   |       | 28,429   |       |
| Industrial                                      |       |        |       |     |       |     |       |     |       |     |       |
| Excluding Delivery Service Only                 | ** ** | **604**     |       | 921      |       | 865      |       | 1,143    |       | 1,207    |       |
| Delivery Service Only                           | ** ** | **20,325**  |       | 19,357   |       | 14,310   |       | 18,399   |       | 23,689   |       |
| System Sales and Deliveries                     | ** ** | **95,274**  |       | 107,934  |       | 107,676  |       | 110,109  |       | 106,676  |       |
| Off-System Sales                                | ** ** | **19,738**  |       | 17,209   |       | 9,914    |       | 12,859   |       | 18,551   |       |
| Total                                           | ** ** | **115,012** |       | 125,143  |       | 117,590  |       | 122,968  |       | 125,227  |       |
| Customers *(In thousands)*                      |       |        |       |     |       |     |       |     |       |     |       |
| Residential                                     | ** ** | **597.1**   |       | 590.9    |       | 582.0    |       | 575.2    |       | 567.3    |       |
| Commercial                                      | ** ** | **42.3**    |       | 42.0     |       | 41.6     |       | 41.1     |       | 40.7     |       |
| Industrial                                      | ** ** | **1.2**     |       | 1.2      |       | 1.2      |       | 1.2      |       | 1.3      |       |
| Total                                           | ** ** | **640.6**   |       | 634.1    |       | 624.8    |       | 617.5    |       | 609.3    |       |

*Operating statistics do not reflect theelimination of intercompany transactions.*

*“Deliveryservice only” refers to BGE’s delivery of commodity that was purchased by thecustomer from an alternate supplier.*

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**Franchises**

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

**Other Nonregulated Businesses**

**Energy Projects andServices**

We offer energy projects andservices designed primarily to provide energy solutions to large commercial andindustrial and governmental customers. These energy products and servicesinclude:

 ̈  designing,constructing, and operating heating, cooling, and cogeneration facilities,

 ̈  energysavings projects and performance contracting,

 ̈  energyconsulting and procurement services ,

 ̈  servicesto enhance the reliability of individual electric supply systems, and

 ̈  customizedfinancing alternatives.

**Home Products andGas Retail Marketing**

We offer services to customersin Maryland including:

 ̈  homeimprovements,

 ̈  theservice of heating, air conditioning, plumbing, electrical, and indoor airquality systems, and

 ̈  thesale of natural gas to residential customers.

**Consolidated Capital Requirements**

Our totalcapital requirements for 2006 were $1,149 million. Of this amount,$789 million was used in our nonregulated businesses and $360 millionwas used in our regulated business. We estimate our total capital requirementswill be $1,915 million in 2007.

We continuously review and change our capital expenditure programs, soactual expenditures may vary from the estimate above. We discuss our capitalrequirements further in *Item 7. Management’sDiscussion and Analysis—Capital Resources* section.

**Environmental Matters**

The development(involving site selection, environmental assessments, and permitting),construction, acquisition, and operation of electric generating anddistribution facilities are subject to extensive federal, state, and localenvironmental and land use laws and regulations. From the beginning phases ofdevelopment to the ongoing operation of existing or new electric generating anddistribution facilities, our activities involve compliance with diverse lawsand regulations that address emissions and impacts to air and water, protectionof natural and cultural resources, and chemical and waste handling and disposal.

We continuously monitor federal, state, and local environmentalinitiatives to determine potential impacts on our financial results. As newlaws or regulations are promulgated, we assess their applicability andimplement the necessary modifications to our facilities or their operation tomaintain ongoing compliance. Our capital expenditures were approximately$100 million during the five-year period 2002-2006 to comply withexisting environmental standards and regulations. Our estimated environmentalcapital requirements for the next three years are approximately$335 million in 2007, $495 million in 2008, and $305 million in2009.

**Air Quality**

***Federal***

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

*NationalAmbient Air Quality Standards (NAAQS)*

The NAAQS arefederal air quality standards authorized under the Clean Air Act that establishmaximum ambient air concentrations for the following specific pollutants: ozone(smog), carbon monoxide, lead, particulates, sulfur dioxides (SO2), and nitrogen dioxides (NO2).

In order for states to achievecompliance with the NAAQS, the Environmental Protection Agency (EPA) adoptedthe Clean Air Interstate Rule (CAIR) in March 2005 to further reduceozone and fine particulate pollution by addressing the interstate transport ofSO2 and nitrogen oxide (NOx) emissions from fossil fuel-firedgenerating facilities located primarily in the Eastern United States.

In May 2005,the EPA adopted a stricter NAAQS for ozone and rescinded a requirement toimpose fees on emissions sources in certain areas, including certain of ourgenerating facilities, for failure to achieve the previous ozone standard.States will be required to submit plans to the EPA to meet the new standard by2007, at which time the standard will take effect. We are unable to determinethe impact that complying with the stricter NAAQS for ozone will have on ourfinancial results until the states in which our generating facilities arelocated adopt plans to meet the new standard.

In December 2006,the United States Court of Appeals for the District of Columbia Circuit ruledthat the requirement to impose fees on emissions sources based on the previousozone standard remained applicable retroactive to November 2005 andremanded the issue to the EPA for reconsideration. At this time, we cannotpredict what action the EPA will take in response to the Court’s decision andwhether the fees will be retroactively assessed. The exact method of computingthese fees has not been established and will depend in part on stateimplementation regulations that have not been finalized. Consequently, we areunable to estimate the ultimate financial impact of the fees in light of theuncertainty surrounding the methodology that 

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will be used in calculating the fees. However, any fees that areultimately assessed could have a material adverse affect on our financialresults.

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

*Hazardous AirEmissions*

In March 2005, the EPA finalized the Clean Air Mercury Rule (CAMR)to reduce the emissions of mercury from coal-fired facilities through a market-basedcap and trade program. CAMR will affect all coal or waste coal fired boilers atour generating facilities.

*New SourceReview*

In connectionwith its enforcement of the Clean Air Act’s new source review requirements, in2000, the EPA requested information relating to modifications made to ourBrandon Shores, Crane, and Wagner plants located in Maryland. The EPA also sentsimilar, but narrower, information requests to two of our newer Pennsylvaniawaste-coal burning plants in which we have an ownership interest. We respondedto the EPA in 2001, and as of the date of this report the EPA has taken nofurther action.

Based on thelevel of emissions control that the EPA and states are seeking in these newsource review enforcement actions, we believe that material additional costsand penalties could be incurred, and planned capital expenditures could beaccelerated, if the EPA was successful in any future actions regarding ourfacilities.

In March 2006, the U.S. Court of Appeals for the District ofColumbia annulled the equipment replacement rule adopted by the EPA inAugust 2003, which established a threshold for determining when major newsource review requirements are triggered. We believe the Court decision, whichwas anticipated, should have minimal effect on us as it maintains the existingrules for equipment replacement. However, we anticipate that the EPA willcontinue to examine the existing equipment replacement rules and may againpropose new rules. In addition, the U.S. Supreme Court has agreed to hear acase, not involving us, relating to the new source review requirements. Wecannot predict the timing or outcome of any future EPA regulatory action or theoutcome of the U.S. Supreme Court proceeding, or their possible effect on ourfinancial results.

***State***

Maryland has adopted the HealthyAir Act (HAA) and the Clean Power Rule (CPR), which establish annual SO2, NOx, andmercury emission caps for specific coal-fired units in Maryland, includingunits located at three of our facilities. The requirements of the HAA and theCPR for SO2, NOx, and mercury emissions are more stringent andapply sooner than those under CAIR and CAMR.

In addition,Pennsylvania has adopted regulations requiring coal-fired generating facilitieslocated in Pennsylvania to reduce mercury emissions sooner and to a greaterextent than required under CAMR.

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

***CapitalExpenditure Estimates***

We expect toincur additional environmental capital spending as a result of complying withthe air quality laws and regulations discussed above. Based on the informationcurrently available to us about CAIR, CAMR, HAA, and CPR, we will installadditional air emission control equipment at our coal-fired generatingfacilities in Maryland and at our co-owned coal-fired facilities inPennsylvania to meet air quality standards. We include in our estimatedenvironmental capital requirements capital spending for these projects, whichwe expect will be approximately $320 million in 2007, $470 million in2008, $290 million in 2009 and $40 million from 2010-2011.

Our estimatesare subject to significant uncertainties including the timing of any additionalfederal and/or state regulations or legislation, the implementation timetablesfor such regulation or legislation, and the specific amount of emissionsreductions that will be required at our facilities. As a result, we cannotpredict our capital spending or the scope or timing of these projects withcertainty, and the actual expenditures, scope and timing could differ significantlyfrom our estimates. In addition, CAMR is subject to legal challenges filed bythe states and industry and environmental groups. We cannot predict the timingor outcome of these challenges, or their possible effect on our financialresults.

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

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*Global Climate Change*

Althoughuncertainty remains as to the nature and timing of greenhouse gas emissionsregulation, there is an increasing likelihood that such regulation will occurat the federal and/or state level. In the event that greenhouse gas emissionsreduction legislation or regulations are enacted, we will assess our variouscompliance alternatives, which may include installation of additionalenvironmental controls, modification of operating schedules or the closure ofone or more of our coal-fired generating facilities. Any compliance costs weincur could have a material impact on our financial results.

The HAArequires that Maryland become a full participant in the Northeast RegionalGreenhouse Gas Initiative (RGGI) by June 2007. Under RGGI, it is expectedthat affected plants would participate in an auction to obtain sufficient CO2 allowances to support the level of emissionsthat result from plant operations.

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

We continue to evaluate the potential impact of the HAA and CaliforniaCO2 emissions requirements and RGGI participationon our financial results; however, our compliance costs could be material.

***Water Quality***

The Clean Water Act established the basic framework for federal andstate regulation of water pollution control and requires facilities thatdischarge waste or storm water into the waters of the United States to obtainpermits.

*Water IntakeRegulations*

In July 2004,the EPA published final rules under the Clean Water Act that requirecooling water intake structures to reflect the best technology available forminimizing adverse environmental impacts. We currently have six facilitiesaffected by the regulation. The rule allows for a number of complianceoptions that will be assessed through 2007, following which we will determinewhether any action is required and what our most viable options are if anyaction is required. Until we determine our most viable option under the finalrules, we cannot estimate our compliance costs. However, the costs associatedwith the final rules could be material.

In January 2007, the United States Court of Appeals for the SecondCircuit ruled that the EPA’s rule did not properly implement the CleanWater Act requirements in a number of areas and remanded the rule to theEPA for reconsideration. At this time, we cannot predict the timing or outcomeof any EPA regulatory action taken in response to the court’s decision. However,any such action could impact our compliance approach, which could have amaterial effect on our financial results.

***Hazardous andSolid Waste***

We discussproceedings relating to compliance with the Comprehensive EnvironmentalResponse, Compensation and Liability Act in *Note 12 to ConsolidatedFinancial Statements*. 

Our coal-firedgenerating facilities produce approximately two and a half million tons ofcombustion by-products (“ash”) each year. The EPA has announced its intentionto develop national standards, currently scheduled to be proposed in May 2007,to regulate this material as a non-hazardous waste, and is developingregulations governing the placement of ash in landfills, surface impoundments,and sand/gravel surface mines.

The EPA is alsodeveloping regulations for ash placement in coal mines, which are expected tobe proposed in October 2007. Federal regulation has the potential toresult in additional requirements. Depending on the scope of any finalrequirements, our compliance costs could be material.

As a result of these regulatory proposals, the remaining ash placementcapacity at our current mine reclamation site and our current ash generationprojections, we are exploring our options for the placement of ash, includingconstruction of an ash placement facility. Over the next five years, weestimate that our capital expenditures for this project will be approximately$75 million. Our estimates are subject to significant uncertaintiesincluding the timing of any regulatory change, its implementation timetable,and the scope of the final requirements. As a result, we cannot predict our capitalspending or the scope and timing of this project with certainty, and the actualexpenditures, scope and timing could differ significantly from our estimates.

**Employees**

Constellation Energy and its subsidiaries had approximately 9,645employees at December 31, 2006. At the Nine Mile Point facility,approximately 515 employees are represented by the International Brotherhood ofElectrical Workers, Local 97. The labor contract with this union expires in June 2011.We believe that our relationship with this union is satisfactory, but there canbe no assurances that this will continue to be the case.

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**Item 1A. Risk Factors**

*Youshould consider carefully the following risks, along with the other informationcontained in this Form 10-K. The risks and uncertainties describedbelow are not the only ones that may affect us. Additional risks anduncertainties also may adversely affect our business and operations includingthose discussed in Item 7. Management’s Discussion and Analysis. If any of thefollowing events actually occur, our business and financial results could bematerially adversely affected.*

**Our merchant energybusiness may incur substantial costs and liabilities and be exposed to pricevolatility and counterparty performance risk as a result of its participationin the wholesale energy markets.**

We purchase andsell power and fuel in markets exposed to significant risks, including pricevolatility for electricity and fuel and the credit risks of counterparties withwhich we enter into trades.

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

*Exposure to electricity price volatility.*   Webuy and sell electricity in both the wholesale bilateral markets and spotmarkets, which exposes us to the risks of rising and falling prices in thosemarkets, and our cash flows may vary accordingly. At any given time, thewholesale spot market price of electricity for each hour is generallydetermined by the cost of supplying the next unit of electricity to the marketduring that hour. This is highly dependent on the regional generation market.In many cases, the next unit of electricity supplied would be supplied fromgenerating stations fueled by fossil fuels, primarily coal, natural gas andoil. Consequently, the open market wholesale price of electricity may reflectthe cost of coal, natural gas or oil plus the cost to convert the fuel toelectricity and an appropriate return on capital. Therefore, changes in thesupply and cost of coal, natural gas and oil may impact the open marketwholesale price of electricity.

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

*Exposure to fuel cost volatility.*   Currently,our power generation facilities purchase a portion of their fuel throughshort-term contracts or on the spot market. Fuel prices can be volatile, andthe price that can be obtained for power produced from such fuel may not changeat the same rate as fuel costs. As a result, fuel price increases may adverselyaffect our financial results.

*Exposure to counterparty performance.*   Ourmerchant energy business enters into trades and hedging transactions withnumerous third parties (commonly referred to as “counterparties”). In sucharrangements, we are exposed to the credit risks of our counterparties and therisk that one or more counterparties may fail to perform their obligations tomake payments or deliver fuel or power. These risks are enhanced during periodsof commodity price fluctuations, such as is currently being experienced in theUnited States. Defaults by suppliers and other counterparties may adverselyaffect our financial results.

**The operation ofpower generation facilities, including nuclear facilities, involves significantrisks that could adversely affect our financial results.**

We own and operate a number of power generation facilities. Theoperation of power generation facilities involves many risks, including startup risks, breakdown or failure of equipment, transmission lines, substations orpipelines, use of new technology, the dependence on a specific fuel source,including the transportation of fuel, or the impact of unusual or adverseweather conditions (including natural disasters such as hurricanes) orenvironmental compliance, as well as the risk of performance below expected orcontracted levels of output or efficiency. This could result in lost revenuesand/or increased expenses. Insurance, warranties, or performance guarantees maynot cover any or all of the lost revenues or increased expenses, including thecost of replacement power. A portion of our generation facilities wereconstructed many years ago. Older generating equipment may require significantcapital expenditures to keep it operating at peak efficiency. This equipment isalso likely to require periodic upgrading and improvement. Breakdown or failureof one of our operating facilities may prevent the facility from performingunder applicable power sales agreements which, in certain situations, couldresult in termination of the agreement or incurring a liability for liquidateddamages.

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

We are subjectto extensive federal, state, and local environmental statutes, rules and regulationsrelating to air quality, water quality, waste management, wildlife protection,the management of natural resources, and the protection of human health andsafety that could, among other things, require additional pollution controlequipment, limit the use of certain fuels, restrict the 

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output ofcertain facilities, or otherwise increase costs. Significant capitalexpenditures, operating and other costs are associated with compliance withenvironmental requirements, and these expenditures and costs could become evenmore significant in the future as a result of regulatory changes.

For example,the State of Maryland has enacted the Healthy Air Act and the Clean Power Rule,which will require, among other things, more rapid emission reductions by Marylandpower generation facilities (including those owned and operated by us) than isrequired by current federal laws and regulations.

We are subjectto liability under environmental laws for the costs of remediatingenvironmental contamination. Remediation activities include the cleanup ofcurrent facilities and former properties, including manufactured gas plantoperations and offsite waste disposal facilities. The remediation costs couldbe significantly higher than the liabilities recorded by us. Also, oursubsidiaries are currently involved in proceedings relating to sites wherehazardous substances have been released and may be subject to additionalproceedings in the future.

We are subjectto legal proceedings by individuals alleging injury from exposure to hazardoussubstances and could incur liabilities that may be material to our financialresults. Additional proceedings could be filed against us in the future.

We may also be required to assume environmental liabilities inconnection with future acquisitions. As a result, we may be liable forsignificant environmental remediation costs and other liabilities arising fromthe operation of acquired facilities, which may adversely affect our financialresults.

**Our generationbusiness may incur substantial costs and liabilities due to its ownership andoperation of nuclear generating facilities.**

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

*Nuclear Operating Risks.*   Theownership and operation of nuclear generating facilities involve routineoperating risks, including:

 ̈  mechanicalor structural problems;

 ̈  inadequacyor lapses in maintenance protocols;

 ̈  impairmentof reactor operation and safety systems due to human or mechanical error;

 ̈  costsof storage, handling and disposal of nuclear materials, including theavailability or unavailability of a permanent repository for spent nuclearfuel;

 ̈  regulatoryactions, including shut down of units because of public safety concerns,whether at our plants or other nuclear operators;

 ̈  limitationson the amounts and types of insurance coverage commercially available;

 ̈  uncertaintiesregarding both technological and financial aspects of decommissioning nucleargenerating facilities; and

 ̈  environmentalrisks, including risks associated with changes in environmental legalrequirements.

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

**We often rely onsingle suppliers and at times on single customers, exposing us to significantfinancial 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 relyon a single customer or a few customers to purchase all or a significantportion of a facility’s output, in some cases under long-term agreements thatprovide the support for any project debt used to finance the facility. Thefailure of any one customer or supplier to fulfill its contractual obligationscould negatively impact our financial results. Consequently, our financialperformance depends on the continued performance by customers and suppliers oftheir obligations under these long-term agreements.

**Reduced liquidityin the markets in which we operate could impair our ability to appropriatelymanage the risks of our operations.**

We are an active participant in energy markets through our competitiveenergy businesses. The liquidity of regional energy markets is an important factorin our ability to manage risks in these operations. Over the past severalyears, several merchant energy businesses have ended or significantly reducedtheir activities as a result of several factors including governmentinvestigations, changes in market design and deteriorating credit quality. As aresult, several regional energy markets experienced a significant decline inliquidity. While there have been recent improvements in liquidity, future reductionsin liquidity may restrict our ability to manage our risks, and could impact ourfinancial results.

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**We may not fullyhedge our generation assets, competitive supply or other market positionsagainst changes in commodity prices, and our hedging procedures may not work asplanned.**

To lower ourfinancial exposure related to commodity price fluctuations, we routinely enterinto contracts to hedge a portion of our purchase and sale commitments, weatherpositions, fuel requirements, inventories of natural gas, coal and othercommodities, and competitive supply. As part of this strategy, we routinelyutilize fixed-price forward physical purchase and sales contracts,futures, financial swaps, and option contracts traded in the over-the-countermarkets or on exchanges. However, we may not cover the entire exposure of ourassets or positions to market price volatility and the coverage will vary overtime. Fluctuating commodity prices may negatively impact our financial resultsto the extent we have unhedged positions.

In addition,daily value at risk and stop loss limits and liquidity guidelines are based onhistorical price movements. If prices significantly or persistently deviatefrom historical prices, the limits may not protect us from significant losses.

Our risk management policies and proceduresmay not always work as planned. As a result of these and other factors, wecannot predict with precision the impact that risk management decisions mayhave on our financial results.

**The use ofderivative contracts by us in the normal course of business could result infinancial losses that negatively impact our financial results.**

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

In the absence of actively quoted market prices and pricing informationfrom external sources, the valuation of these derivative instruments involvesmanagement’s judgment or use of estimates. As a result, changes in theunderlying assumptions or use of alternative valuation methods could affect thereported fair value of these contracts.

**We operate inderegulated segments of the electric and gas industries created by federal andstate restructuring initiatives. If competitive restructuring of the electricor gas industries is reversed, discontinued, restricted or delayed, ourbusiness prospects and financial results could be materially adverselyaffected.**

The regulatoryenvironment applicable to the electric and natural gas industries has undergonesubstantial changes as a result of restructuring initiatives at both the stateand federal levels. These initiatives have had a significant impact on thenature of the electric and natural gas industries and the manner in which theirparticipants conduct their businesses. We have targeted the competitivesegments of the electric and natural gas industries created by theseinitiatives.

Due to recentevents in the energy markets, energy companies have been under increasedscrutiny by state legislatures, regulatory bodies, capital markets and creditrating agencies. This increased scrutiny could lead to substantial changes inlaws and regulations affecting us, including modifications to the auctionprocesses in competitive markets and new accounting standards that could changethe way we are required to record revenues, expenses, assets and liabilities.The Maryland energy legislation enacted in June 2006 is one example of howthese laws can change. We cannot predict the future development of regulationin these markets or the ultimate effect that this changing regulatoryenvironment will have on our business.

If competitive restructuring of the electric and natural gas markets isreversed, discontinued, restricted or delayed, or if the recently enactedMaryland energy legislation is implemented or interpreted in a manner adverseto us, our business prospects and financial results could be negativelyimpacted.

**Our financialresults may be harmed if transportation and transmission availability islimited or unreliable.**

We have business operations throughout the United States andinternationally. As a result, we depend on transportation and transmissionfacilities owned and operated by utilities and other energy companies todeliver the electricity, coal, and natural gas we sell to the wholesale andretail markets, as well as the natural gas and coal we purchase to supply someof our generating facilities. If transportation or transmission is disrupted,or transportation or transmission capacity is inadequate, our ability to selland deliver products may be hindered. Such disruptions could also hinder ourability to provide electricity or natural gas to our retail electric and gascustomers and may materially adversely affect our financial results.

**Our merchant energybusiness has contractual obligations to certain customers to provide fullrequirements service, which makes it difficult to predict and plan for loadrequirements and may result in increased operating costs to our business.**

Our merchant energy business has contractual obligations to certaincustomers to supply full requirements service to such customers to satisfy allor a portion of their energy requirements. The uncertainty regarding the amountof load that our merchant energy business must be prepared to supply tocustomers may 

20

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increase our operating costs. A significant under- orover-estimation of load requirements could result in our merchant energybusiness not having enough or having too much power to cover its loadobligation, in which case it would be required to buy or sell power from or tothird parties at prevailing market prices. Those prices may not be favorableand thus could increase our operating costs.

**Our financialresults may fluctuate on a seasonal and quarterly basis or as a result ofsevere weather.**

Our business isaffected by weather conditions. Our overall operating results may fluctuatesubstantially on a seasonal basis, and the pattern of this fluctuation maychange depending on the nature and location of any facility we acquire and theterms of any contract to which we become a party. Weather conditions directlyinfluence the demand for electricity and natural gas and affect the price ofenergy commodities.

Generally,demand for electricity peaks in winter and summer and demand for gas peaks inthe winter. Typically, when winters are warmer than expected and summers arecooler than expected, demand for energy is lower, resulting in less electricand gas consumption than forecasted. Depending on prevailing market prices for electricityand gas, these and other unexpected conditions may reduce our revenues andresults of operations. First and third quarter financial results, inparticular, are substantially dependent on weather conditions, and may makeperiod comparisons less relevant. Severe weather can affect our results ofoperation.

Severe weather can be destructive, causing outages and/or propertydamage. 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 amaterial adverse effect on our financial results.

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

We rely onaccess to capital markets as a source of liquidity for capital requirements notsatisfied by operating cash flows. If any of our credit ratings were to bedowngraded, especially below investment grade, our ability to raise capital onfavorable terms, including the commercial paper markets, could be hindered, andour borrowing costs would increase. Additionally, the business prospects of ourwholesale and retail competitive supply businesses, which in many cases rely onthe creditworthiness of Constellation Energy, would be negatively impacted.Some of the factors that affect credit ratings are cash flows, liquidity, andthe amount of debt as a component of total capitalization.

In addition, the ability of BGE to recover its costs of providingservice and timing of BGE’s recovery could have a material adverse effect onthe credit ratings of BGE and us.

**We, and BGE inparticular, are subject to extensive state and federal regulation that couldaffect our operations and costs.**

We are subjectto regulation by federal and state governmental entities, including the FederalEnergy Regulatory Commission, the Nuclear Regulatory Commission, the MarylandPSC and the utility commissions of other states in which we have operations. Inaddition, changing governmental policies and regulatory actions can have asignificant impact on us. Regulations can affect, for example, allowed rates ofreturn, requirements for plant operations, recovery of costs, limitations ondividend payments and the regulation or re-regulation of wholesale and retailcompetition (including but not limited to retail choice and transmissioncosts).

BGE’sdistribution rates are subject to regulation by the Maryland PSC, and suchrates are effective until new rates are approved. In addition, limitedcategories of costs are recovered through adjustment charges that areperiodically reset to reflect current and projected costs. Inability to recovermaterial costs not included in rates or adjustment clauses, including increasesin uncollectible customer accounts that may result from higher gas or electriccosts, could have an adverse effect on our, or BGE’s, cash flow and financialposition.

Energylegislation enacted in Maryland in June 2006 mandates rate stabilizationthat requires BGE to defer the recovery of a portion of its purchased powercosts and to phase in the recovery of these costs over a period of years. Inaddition, the legislation mandates that the Maryland PSC conduct a comprehensivereview of Maryland’s deregulated electricity market. Because this energylegislation is still in the process of being implemented and interpreted, we donot know the final impact such legislation will have on our, or BGE’s,business.

The regulatory process may restrict our ability to grow earnings incertain parts of our business, cause delays in or affect business planning andtransactions and increase our, or BGE’s, costs.

**Poor marketperformance will affect our benefit plan and nuclear decommissioning trustasset values, which may adversely affect our liquidity and financial results.**

Our qualifiedpension obligations have exceeded the fair value of our plan assets since 2001.At December 31, 2006, our qualified pension obligations were approximately$405 million greater than the fair value 

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of our planassets. The performance of the capital markets will affect the value of theassets that are held in trust to satisfy our future obligations under ourqualified pension plans. A decline in the market value of those assets mayincrease our funding requirements for these obligations, which may adverselyaffect our liquidity and financial results.

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

**War and threats ofterrorism and catastrophic events that could result from terrorism may impactour results of operations in unpredictable ways.**

We cannotpredict the impact that any future terrorist attacks may have on the energyindustry in general and on our business in particular. In addition, anyretaliatory military strikes or sustained military campaign may affect ouroperations in unpredictable ways, such as changes in insurance markets anddisruptions of fuel supplies and markets, particularly oil. The possibilityalone that infrastructure facilities, such as electric generation, electric andgas transmission and distribution facilities, would be direct targets of, orindirect casualties of, an act of terror may affect our operations.

Such activity may have an adverse effect on the United States economyin general. A lower level of economic activity might result in a decline inenergy consumption, which may adversely affect our financial results orrestrict our future growth. Instability in the financial markets as a result ofterrorism or war may affect our stock price and our ability to raise capital.

**We are subject toemployee workforce factors that could affect our businesses and financialresults.**

We are subject to employee workforce factors, including loss orretirement of key executives or other employees, availability of qualifiedpersonnel, collective bargaining agreements with union employees, and work stoppage thatcould affect our financial results. In particular, our competitive energybusinesses are dependent, in part, on recruiting and retaining personnel withexperience in sophisticated energy transactions and the functioning of complexwholesale markets.

**Our ability tosuccessfully identify, complete and integrate acquisitions is subject to significantrisks, including the effect of increased competition.**

We are likely to encounter significant competition for acquisitionopportunities that may become available. In addition, we may be unable toidentify attractive acquisition opportunities at favorable prices and tosuccessfully and timely complete and integrate them.

**Item 2. Properties**

ConstellationEnergy’s corporate offices occupy approximately 106,000 square feet of leasedoffice space in Baltimore, Maryland. The corporate offices for most of ourmerchant energy business occupy approximately 268,000 square feet of leasedoffice space in another building in Baltimore, Maryland. We describe ourelectric generation properties on the next page. We also have leases for otheroffices and services located in the Baltimore metropolitan region, and forvarious real property and facilities relating to our generation projects.

BGE owns itsprincipal headquarters building located in downtown Baltimore. In addition, BGEowns propane air and liquefied natural gas facilities as discussed in *Item 1. Business—Gas Business* section.

BGE also hasrights-of-way to maintain 26-inch natural gas mains across certainBaltimore City-owned property (principally parks) which expired in 2004. BGE isin the process of renewing the rights-of-way with Baltimore City for anadditional 25 years. The expiration of the rights-of-way does not affectBGE’s ability to use the rights-of-way during the renewal process.

BGE has electric transmission and electric and gas distribution lineslocated:

 ̈  inpublic streets and highways pursuant to franchises, and

 ̈  onrights-of-way secured for the most part by grants from owners of the property.

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

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

Our merchantenergy business owns several natural gas producing properties. We also leaseoffice space throughout North America, and in the United Kingdom and Australiato support our merchant energy business.

 

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The following table describes our generatingfacilities:
| **Plant**                                      | ** ** | **Location**                   | ** ** | **Capacity (MW)**                    | ** ** | **%  Owned** | ** ** | **Capacity  Owned (MW)** | ** ** | **Primary Fuel** | ** ** |
|------------------------------------------------|------------|--------------------------------|------------|-------------------------------------------|------------|--------------|------------|-------------------------------|------------|-----------------------|------------|
| ** **                                     | ** ** | ** **                     | ** ** | **(at December 31, 2006)** | ** ** |
| *Mid-Atlantic Region*                          |       |                           |       |                                      |       |         |       |                          |       |                  |       |   |   |   |   |   |   |
| Calvert Cliffs                                 |       | Calvert Co., MD                |       |                                      | 1,735      |         |       |                          | 100.0      |                  |       |   | 1,735 |   |   | Nuclear |   |
| Brandon Shores                                 |       | Anne Arundel Co., MD           |       |                                      | 1,286      |         |       |                          | 100.0      |                  |       |   | 1,286 |   |   | Coal |   |
| H. A. Wagner                                   |       | Anne Arundel Co., MD           |       |                                      | 963        |         |       |                          | 100.0      |                  |       |   | 963 |   |   | Coal/Oil/Gas |   |
| C. P. Crane                                    |       | Baltimore Co., MD              |       |                                      | 399        |         |       |                          | 100.0      |                  |       |   | 399 |   |   | Oil/Coal |   |
| Keystone                                       |       | Armstrong and Indiana Cos., PA |       |                                      | 1,706      |         |       |                          | 21.0       |                  |       |   | 358 | (A) |   | Coal |   |
| Conemaugh                                      |       | Indiana Co., PA                |       |                                      | 1,714      |         |       |                          | 10.6       |                  |       |   | 181 | (A) |   | Coal |   |
| Perryman                                       |       | Harford Co., MD                |       |                                      | 355        |         |       |                          | 100.0      |                  |       |   | 355 |   |   | Oil/Gas |   |
| Riverside                                      |       | Baltimore Co., MD              |       |                                      | 200        |         |       |                          | 100.0      |                  |       |   | 200 |   |   | Oil/Gas |   |
| Handsome Lake                                  |       | Rockland Twp, PA               |       |                                      | 250        |         |       |                          | 100.0      |                  |       |   | 250 |   |   | Gas |   |
| Notch Cliff                                    |       | Baltimore Co., MD              |       |                                      | 120        |         |       |                          | 100.0      |                  |       |   | 120 |   |   | Gas |   |
| Westport                                       |       | Baltimore City, MD             |       |                                      | 116        |         |       |                          | 100.0      |                  |       |   | 116 |   |   | Gas |   |
| Philadelphia Road                              |       | Baltimore City, MD             |       |                                      | 64         |         |       |                          | 100.0      |                  |       |   | 64 |   |   | Oil |   |
| Safe Harbor                                    |       | Safe Harbor, PA                |       |                                      | 417        |         |       |                          | 66.7       |                  |       |   | 278 |   |   | Hydro |   |
| *Total Mid-Atlantic Region*                    |       |                           |       |                                      | 9,325      |         |       |                          |       |                  |       |   | 6,305 |   |   |   |   |
| *Plants  with Power Purchase Agreements*       |       |                           |       |                                      |       |         |       |                          |       |                  |       |   |   |   |   |
| Nine Mile Point Unit 1                         |       | Scriba, NY                     |       |                                      | 620        |         |       |                          | 100.0      |                  |       |   | 620 |   |   | Nuclear |   |
| Nine Mile Point Unit 2                         |       | Scriba, NY                     |       |                                      | 1,138      |         |       |                          | 82.0       |                  |       |   | 933 |   |   | Nuclear |   |
| R.E. Ginna                                     |       | Ontario, NY                    |       |                                      | 581        |         |       |                          | 100.0      |                  |       |   | 581 |   |   | Nuclear |   |
| *Total Plants with Power Purchase  Agreements* |       |                           | 2,339      |                                      |       |         |       |                          |       |                  | 2,134      |   |   |   |   |
| *Other*                                        |       |                           |       |                                      |       |         |       |                          |       |                  |       |   |   |   |   |
| Panther Creek                                  |       | Nesquehoning, PA               |       |                                      | 80         |         |       |                          | 50.0       |                  |       |   | 40 |   |   | Waste Coal |   |
| Colver                                         |       | Colver Township, PA            |       |                                      | 104        |         |       |                          | 25.0       |                  |       |   | 26 |   |   | Waste Coal |   |
| Sunnyside                                      |       | Sunnyside, UT                  |       |                                      | 52         |         |       |                          | 50.0       |                  |       |   | 26 |   |   | Waste Coal |   |
| ACE                                            |       | Trona, CA                      |       |                                      | 102        |         |       |                          | 31.1       |                  |       |   | 32 |   |   | Coal |   |
| Jasmin                                         |       | Kern Co., CA                   |       |                                      | 34         |         |       |                          | 50.0       |                  |       |   | 17 |   |   | Coal |   |
| POSO                                           |       | Kern Co., CA                   |       |                                      | 34         |         |       |                          | 50.0       |                  |       |   | 17 |   |   | Coal |   |
| Mammoth Lakes G-1                              |       | Mammoth Lakes, CA              |       |                                      | 6          |         |       |                          | 50.0       |                  |       |   | 3 |   |   | Geothermal |   |
| Mammoth Lakes G-2                              |       | Mammoth Lakes, CA              |       |                                      | 12         |         |       |                          | 50.0       |                  |       |   | 6 |   |   | Geothermal |   |
| Mammoth Lakes G-3                              |       | Mammoth Lakes, CA              |       |                                      | 12         |         |       |                          | 50.0       |                  |       |   | 6 |   |   | Geothermal |   |
| Soda Lake I                                    |       | Fallon, NV                     |       |                                      | 4          |         |       |                          | 50.0       |                  |       |   | 2 |   |   | Geothermal |   |
| Soda Lake II                                   |       | Fallon, NV                     |       |                                      | 10         |         |       |                          | 50.0       |                  |       |   | 5 |   |   | Geothermal |   |
| Rocklin                                        |       | Placer Co., CA                 |       |                                      | 24         |         |       |                          | 50.0       |                  |       |   | 12 |   |   | Biomass |   |
| Fresno                                         |       | Fresno, CA                     |       |                                      | 24         |         |       |                          | 50.0       |                  |       |   | 12 |   |   | Biomass |   |
| Chinese Station                                |       | Jamestown, CA                  |       |                                      | 22         |         |       |                          | 45.0       |                  |       |   | 10 |   |   | Biomass |   |
| Malacha                                        |       | Muck Valley, CA                |       |                                      | 32         |         |       |                          | 50.0       |                  |       |   | 16 |   |   | Hydro |   |
| SEGS IV                                        |       | Kramer Junction, CA            |       |                                      | 33         |         |       |                          | 12.2       |                  |       |   | 4 |   |   | Solar |   |
| SEGS V                                         |       | Kramer Junction, CA            |       |                                      | 24         |         |       |                          | 4.2        |                  |       |   | 1 |   |   | Solar |   |
| SEGS VI                                        |       | Kramer Junction, CA            |       |                                      | 34         |         |       |                          | 8.8        |                  |       |   | 3 |   |   | Solar |   |
| *Total Other*                                  |       |                           |       |                                      | 643        |         |       |                          |       |                  |       |   | 238 |   |   |   |   |
| *Total  Generating Facilities*                 |       |                           |       |                                      | 12,307     |         |       |                          |       |                  |       |   | 8,677 |   |   |   |   |

(A)           Reflectsour proportionate interest in and entitlement to capacity from Keystone andConemaugh, which include 2 MW of diesel capacity for Keystone and 1 MW ofdiesel capacity for Conemaugh.

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The following table describes our processingfacilities:
| **Plant**                        | ** ** | **Location**    | ** ** | ** ** | **%  Owned** | ** **            | ** ** | **Primary  Fuel** | ** ** |
|----------------------------------|------------|-----------------|------------|------------|--------------|-----------------------|------------|-------------------|------------|
| A/C Fuels                        |       | Hazelton, PA    |       | 50.0       |         | Waste Coal Processing |       |
| Gary PCI                         |       | Gary, IN        |       | 24.5       |         | Coal Processing       |       |
| Low Country                      |       | Cross, SC       |       | 99.0       |         | Synfuel Processing    |       |
| PC Synfuel VA I                  |       | Norton, VA      |       | 16.7       |         | Synfuel Processing    |       |
| PC Synfuel WV I                  |       | Chelyan, WV     |       | 16.7       |         | Synfuel Processing    |       |
| PC Synfuel WV II                 |       | Mount Storm, WV |       | 16.7       |         | Synfuel Processing    |       |
| PC Synfuel WV III |       | Chester, VA     |       | 16.7       |         | Synfuel Processing    |       |
|                             |       |            |       |       |         |                  |       |

 

**Item 3. Legal Proceedings**

We discuss ourlegal proceedings in *Note 12 toConsolidated Financial Statements.*

** **

**Item 4. Submission of Matters to Vote ofSecurity Holders**

On December 8, 2006, we held our annualmeeting of shareholders. At that meeting, the following matters were votedupon:

1.                 Class IDirectors nominated by Constellation Energy were elected to serve for a term toexpire in 2009 and until their successors are duly elected and qualified asfollows:
| ** **           | ** ** | **COMMON SHARES CAST:** | ** ** |
|----------------------|------------|-------------------------|------------|
| ** **           | ** ** | **For**                 | ** ** | **Withheld** | ** ** |
| Douglas L. Becker    |       | 119,241,432             |       | 14,048,574 |   |
| Edward A. Crooke     |       | 122,520,333             |       | 10,769,673 |   |
| Mayo A. Shattuck III |       | 128,640,389             |       | 4,649,617 |   |
| Michael D. Sullivan  |       | 119,327,025             |       | 13,962,981 |   |

 

All other directors whose term of officecontinued after the date of this meeting are:
| James T. Brady     |   | Freeman A. Hrabowski, III |
|--------------------|--------|--------------------------------|
| James R. Curtiss   |   | Nancy Lampton                  |
| Yves C. de Balmann |   | Robert J. Lawless              |
|               |   | Lynn M. Martin                 |

 

2.                 Theratification of PricewaterhouseCoopers LLP as independent registered publicaccounting firm for 2006 was approved. With respect to holders of common stock,the number of affirmative votes cast was 130,005,402, the number of votes castagainst was 1,846,861, and the number of abstentions was 1,437,743.

3.                 The shareholderproposal requesting Constellation Energy to declassify the Board of Directorswas approved. With respect to holders of common stock, the number ofaffirmative votes cast was 76,259,034, the number of votes cast against was7,688,559, the number of abstentions was 26,748,840, and the number of brokernon-votes was 22,593,573.

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**Executive Officers of the Registrant**
| ** **           | **Name** | ** ** | ** ** | ** **                                                                                                                                                                                                                                                                                                       | **Age** | ** **                                                                                                                                                               | ** ** | **Present Office** | ** ** | ** ** | ** ** | **Other   Offices or Positions Held   During Past Five Years** | ** ** | ** ** |
|----------------------|----------|------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------|------------|------------|------------|----------------------------------------------------------------|------------|------------|
| Mayo A. Shattuck III |     | 52         |       | Chairman of the Board of  Constellation Energy (since July 2002), President and Chief Executive  Officer of Constellation Energy (since November 2001); and Chairman of  the Board of BGE (since July 2002)                                                                                       |    | None.                                                                                                                                                                    |       |
| E. Follin  Smith     |     | 47         |       | Executive Vice President  (since January 2004), Chief Financial Officer (since June 2001) and  Chief Administrative Officer (since January 2004) of Constellation  Energy; and Senior Vice President and Chief Financial Officer of Baltimore  Gas and Electric Company (since January 2002) |    | Senior Vice  President—Constellation Energy.                                                                                                                        |       |
| Thomas V. Brooks     |     | 44         |       | Chairman of Constellation  Energy Commodities Group, Inc. (since August 2005); and Vice  Chairman (since August 2005) and Executive Vice President (since  January 2004) of Constellation Energy                                                                                             |    | President and Chief Executive  Officer—Constellation Energy Commodities Group, Inc.                                                                            |       |
| Michael J.  Wallace  |     | 59         |       | President (since  January 2002) and Chief Executive Officer (since May 2005) of  Constellation Generation Group, LLC; and Executive Vice President of  Constellation Energy (since January 2004)                                                                                                  |    | None.                                                                                                                                                                    |       |
| Thomas F.  Brady     |     | 57         |       | Executive Vice President,  Corporate Strategy and Retail Competitive Supply of Constellation Energy  (since January 2004)                                                                                                                                                                                   |    | Senior Vice President,  Corporate Strategy and Development—Constellation Energy; and Vice President,  Corporate Strategy and Development—Constellation Energy. |       |
| Irving B.  Yoskowitz |     | 61         |       | Executive Vice President and  General Counsel of Constellation Energy (since June 2005)                                                                                                                                                                                                                     |    | Senior  Counsel—Crowell & Moring (law firm); and Senior Partner—Global  Technology Partners, LLC (investment banking and consulting firm).            |       |
| Felix J.  Dawson     |     | 39         |       | Senior Vice President of  Constellation Energy (since October 2006); and Co-President and Co-Chief  Executive Officer of Constellation Energy Commodities Group, Inc. (since  August 2005); President and Chief Executive Officer of Constellation  Energy Partners LLC (since May 2006)     |    | Co-Chief Commercial  Officer—Constellation Energy Commodities Group, Inc.; and Managing  Director—Constellation Energy Commodities Group, Inc.       |       |

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| George E. Persky               |   | 37 |   | Senior Vice President of  Constellation Energy (since October 2006); and Co-President and Co-Chief  Executive Officer of Constellation Energy Commodities Group, Inc. (since  August 2005)                 |   | Co-Chief Commercial  Officer—Constellation Energy Commodities Group, Inc.; and Managing  Director—Constellation Energy Commodities Group, Inc. |   |
|--------------------------------|--------|----|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|
| Kenneth W.  DeFontes, Jr. |   | 56 |   | President and Chief Executive  Officer of Baltimore Gas and Electric Company and Senior Vice President of  Constellation Energy (since October 2004)                                                                 |   | Vice President, Electric  Transmission and Distribution—BGE.                                                                                                  |   |
| Paul J. Allen                  |   | 55 |   | Senior Vice President,  Corporate Affairs of Constellation Energy (since January 2004)                                                                                                                               |   | Vice President, Corporate  Affairs—Constellation Energy.                                                                                                      |   |
| John R.  Collins               |   | 49 |   | Senior Vice President (since  January 2004) and Chief Risk Officer of Constellation Energy (since  December 2001); and member of Board of Managers of Constellation Energy  Partners LLC (since September 2006) |   | Vice President—Constellation  Energy.                                                                                                                         |   |
| Beth S.  Perlman               |   | 46 |   | Senior Vice President (since  January 2004) and Chief Information Officer of Constellation Energy  (since April 2002)                                                                                           |   | Vice President—Constellation  Energy; and Vice President, Technology—Enron Corporation.                                                                  |   |
| Marc L. Ugol                   |   | 48 |   | Senior Vice President, Human  Resources of Constellation Energy (since January 2004)                                                                                                                                 |   | Vice President, Human  Resources—Constellation Energy; and Senior Vice President, Human Resources  and Administration—Tellabs, Inc.                 |   |

 

Officers areelected by, and hold office at the will of, the Board of Directors and do notserve a “term of office” as such. There is no arrangement or understandingbetween any director or officer and any other person pursuant to which thedirector or officer was selected.

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**PART II**

**Item 5. Market for Registrant’s Common Equityand Related Shareholder Matters**

**Stock Trading**

ConstellationEnergy’s common stock is traded under the ticker symbol CEG. It is listed onthe New York and Chicago stock exchanges.

As of January 31, 2007, there were 41,680 common shareholders ofrecord.

**Dividend Policy**

ConstellationEnergy pays dividends on its common stock after its Board of Directors declaresthem. There are no contractual limitations on Constellation Energy payingcommon stock dividends.

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

In January 2007,we announced an increase in our quarterly dividend from $0.3775 to $0.435 pershare payable April 2, 2007 to holders of record on March 12, 2007.This is equivalent to an annual rate of $1.74 per share.

Quarterlydividends were declared on our common stock during 2006 and 2005 in the amountsset forth below.

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

 ̈  BGEelects to defer interest payments on the 6.20% Deferrable Interest SubordinatedDebentures due 2043, and any deferred interest remains unpaid; or

 ̈  anydividends (and any redemption payments) due on BGE’s preference stock have notbeen paid.

 

**CommonStock Dividends and Price Ranges**
| ** **      | ** ** | **2006**     | ** ** | **2005**  | ** ** |
|-----------------|------------|--------------|------------|-----------|------------|
| ** **      | ** ** | **Dividend** | ** ** | **Price** | ** ** | **Dividend** | ** ** | **Price** | ** ** |
| ** **      | ** ** | **Declared** | ** ** | **High**  | ** ** | **Low** | ** ** | **Declared** | ** ** | **High** | ** ** | **Low** | ** ** |
| First Quarter   |       |         | $          | 0.3775    |       |   | $ | 60.55 |   | $ | 54.01 |   |   | $ | 0.335 |   |   | $ | 53.55 |   | $ | 43.01 |   |
| Second  Quarter |       |         | 0.3775     |      |       | 55.68 |   | 50.55 |   |   | 0.335 |   |   | 57.91 |   | 50.36 |   |
| Third Quarter   |       |         | 0.3775     |      |       | 60.79 |   | 53.70 |   |   | 0.335 |   |   | 62.09 |   | 56.50 |   |
| Fourth  Quarter |       |         | 0.3775     |      |       | 70.20 |   | 59.00 |   |   | 0.335 |   |   | 62.60 |   | 50.40 |   |
| Total           |       |         | $          | 1.51      |       |   |   |   |   |   |   | $ | 1.340 |   |   |   |   |   |   |
|                 |            |              |            |           |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

**Unregistered Salesof Equity Securities and Use of Proceeds**

The following table presents sharessurrendered by employees to exercise stock options and to satisfy taxwithholding obligations on vested restricted stock and stock option exercises.
| ** **                                              | **Period** | ** ** | ** ** | **Total Number  of Shares  Purchased** | ** ** | **Average Price  Paid for Shares** | ** ** | **Total Number  of Shares  Purchased as  Part of Publicly  Announced  Plans or  Programs** | ** ** | **Maximum Number  of Shares that  May Yet Be  Purchased Under  the Plans and  Programs** | ** ** |
|---------------------------------------------------------|------------|------------|------------|--------------------------------------------------|------------|---------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------------------|------------|
| October 1 – October 31, 2006   |       |       | 565        |                                             |       |                                              | $          | 60.43                                                                                                                    |       |                                                                                                                             |       | — |   |   |   | — |   |   |
| November 1 – November 30, 2006 |       |       | —     |                                             |       |                                              | —     |                                                                                                                     |       |                                                                                                                             | —     |   |   |   | — |   |   |
| December 1 – December 31, 2006 |       |       | 2,483      |                                             |       |                                              | 68.61      |                                                                                                                     |       |                                                                                                                             | —     |   |   |   | — |   |   |
| Total                                                   |       |       | 3,048      |                                             |       |                                              | $          | 67.09                                                                                                                    |       |                                                                                                                             |       | — |   |   |   | — |   |   |

 

27

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**Item 6. Selected Financial Data**

***Constellation EnergyGroup, Inc. and Subsidiaries***
| ** **                                                                                                                                 | ** ** | **2006**                                                               | ** **   | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002**(1) | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------|--------------|----------|------------|----------|------------|----------|------------|-------------|------------|
| ** **                                                                                                                                 | ** ** | ***(In millions, except per share amounts)*** | ** **   |
| **Summary of Operations**                                                                                                                  | ** ** | ** **                                                             |         |     |       |     |       |     |       |        |       |
| Total Revenues                                                                                                                             | ** ** | **$**                                                                  | **19,284.9** |     | $          | 16,968.3 |       | $        | 12,127.2   |        | $          | 9,342.8 |   | $ | 4,771.6 |   |
| Total Expenses                                                                                                                             | ** ** | **18,025.2**                                                           |         | 16,023.8 |       | 11,209.1 |       | 8,395.5  |       | 3,711.5     |       |
| Gain on Sale of Gas-Fired  Plants                                                                                                          | ** ** | **73.8**                                                               |         | —   |       | —   |       | —   |       | —      |       |
| Income From Operations                                                                                                                     | ** ** | **1,333.5**                                                            |         | 944.5    |       | 918.1    |       | 947.3    |       | 1,060.1     |       |
| Gain on Initial Public  Offering of CEP LLC                                                                                                | ** ** | **28.7**                                                               |         | —   |       | —   |       | —   |       | —      |       |
| Other Income                                                                                                                               | ** ** | **66.1**                                                               |         | 65.5     |       | 25.5     |       | 20.6     |       | 33.8        |       |
| Fixed Charges                                                                                                                              | ** ** | **328.7**                                                              |         | 310.2    |       | 326.8    |       | 336.3    |       | 277.3       |       |
| Income Before Income  Taxes                                                                                                                | ** ** | **1,099.6**                                                            |         | 699.8    |       | 616.8    |       | 631.6    |       | 816.6       |       |
| Income Taxes                                                                                                                               | ** ** | **351.0**                                                              |         | 163.9    |       | 118.4    |       | 222.2    |       | 301.2       |       |
| Income from Continuing  Operations and Before Cumulative Effects of Changes in Accounting Principles                                       | ** ** | **748.6**                                                              |         | 535.9    |       | 498.4    |       | 409.4    |       | 515.4       |       |
| Income from Discontinued  Operations, Net of Income Taxes                                                                                  | ** ** | **187.8**                                                              |         | 94.4     |       | 41.3     |       | 66.3     |       | 10.2        |       |
| Cumulative Effects of  Changes in Accounting Principles, Net of Income Taxes                                                               | ** ** | **—**                                                             |         | (7.2     | )          | —   |       | (198.4   | )          | —      |       |
| Net Income                                                                                                                                 | ** ** | **$**                                                                  | **936.4**    |     | $          | 623.1    |       | $        | 539.7      |        | $          | 277.3 |   | $ | 525.6 |   |
| Earnings Per Common Share  from Continuing Operations and Before Cumulative Effects of Changes in  Accounting Principles Assuming Dilution | ** ** | **$**                                                                  | **4.12**     |     | $          | 2.98     |       | $        | 2.88       |        | $          | 2.45 |   | $ | 3.14 |   |
| Income from Discontinued  Operations                                                                                                       | ** ** | **1.04**                                                               |         | 0.53     |       | 0.24     |       | 0.40     |       | 0.06        |       |
| Cumulative Effects of  Changes in Accounting Principles                                                                                    | ** ** | **—**                                                             |         | (0.04    | )          | —   |       | (1.19    | )          | —      |       |
| Earnings Per Common Share  Assuming Dilution                                                                                               | ** ** | **$**                                                                  | **5.16**     |     | $          | 3.47     |       | $        | 3.12       |        | $          | 1.66 |   | $ | 3.20 |   |
| Dividends Declared Per  Common Share                                                                                                       | ** ** | **$**                                                                  | **1.51**     |     | $          | 1.34     |       | $        | 1.14       |        | $          | 1.04 |   | $ | 0.96 |   |
| **Summary of Financial Condition**                                                                                                         | ** ** | ** **                                                             |         |     |       |     |       |     |       |        |       |
| Total Assets                                                                                                                               | ** ** | **$**                                                                  | **21,801.6** |     | $          | 21,473.9 |       | $        | 17,347.1   |        | $          | 15,593.0 |   | $ | 14,943.3 |   |
| Current Portion of Long-Term  Debt                                                                                                         | ** ** | **$**                                                                  | **878.8**    |     | $          | 491.3    |       | $        | 480.4      |        | $          | 343.2 |   | $ | 426.2 |   |
| Capitalization                                                                                                                             | ** ** | ** **                                                             |         |     |       |     |       |     |       |        |       |
| Long-Term Debt                                                                                                                             | ** ** | **$**                                                                  | **4,222.3**  |     | $          | 4,369.3  |       | $        | 4,813.2    |        | $          | 5,039.2 |   | $ | 4,613.9 |   |
| Minority Interests                                                                                                                         | ** ** | **94.5**                                                               |         | 22.4     |       | 90.9     |       | 113.4    |       | 105.3       |       |
| Preference Stock Not  Subject to Mandatory Redemption                                                                                      | ** ** | **190.0**                                                              |         | 190.0    |       | 190.0    |       | 190.0    |       | 190.0       |       |
| Common Shareholders’  Equity                                                                                                          | ** ** | **4,609.3**                                                            |         | 4,915.5  |       | 4,726.9  |       | 4,140.5  |       | 3,862.3     |       |
| Total Capitalization                                                                                                                       | ** ** | **$**                                                                  | **9,116.1**  |     | $          | 9,497.2  |       | $        | 9,821.0    |        | $          | 9,483.1 |   | $ | 8,771.5 |   |
| **Financial  Statistics at Year End**                                                                                                      | ** ** | ** **                                                             |         |     |       |     |       |     |       |        |       |
| Ratio of Earnings to  Fixed Charges                                                                                                        | ** ** | **4.05**                                                               |         | 3.04     |       | 2.71     |       | 2.69     |       | 3.31        |       |
| Book Value Per Share of  Common Stock                                                                                                      | ** ** | **$**                                                                  | **25.54**    |     | $          | 27.57    |       | $        | 26.81      |        | $          | 24.68 |   | $ | 23.44 |   |

 

*Certain prior-year amounts have been reclassified to conform with thecurrent year’s presentation.*

(1)            *Total revenues for the year ended December 31, 2002 include$255.5 million of gains recognized on the sale of our outstanding sharesof Orion Power Holdings, Inc.*

We discussitems that affect comparability between years, including acquisitions anddispositions, accounting changes and other items, in *Item 7. Management’s Discussion and Analysis*.

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***Baltimore Gas and Electric Company and Subsidiaries***
| ** **                                                                       | ** ** | **2006**                 | ** **  | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|----------------------------------------------------------------------------------|------------|--------------------------|-------------|----------|------------|----------|------------|----------|------------|----------|------------|
| ** **                                                                       | ** ** | ***(In millions)*** | ** **  |
| **Summary  of Operations**                                                       |       |                     |        |     |       |     |       |     |       |     |       |
| Total Revenues                                                                   | ** ** | **$**                    | **3,015.4** |     | $          | 3,009.3  |       | $        | 2,724.7    |     | $          | 2,647.6 |   | $ | 2,547.3 |   |
| Total Expenses                                                                   | ** ** | **2,646.3**              |        | 2,612.8  |       | 2,353.3  |       | 2,262.6  |       | 2,181.0  |       |
| Income From Operations                                                           | ** ** | **369.1**                |        | 396.5    |       | 371.4    |       | 385.0    |       | 366.3    |       |
| Other Income (Expense)                                                           | ** ** | **6.0**                  |        | 5.9      |       | (6.4     | )          | (5.4     | )          | 10.7     |       |
| Fixed Charges                                                                    | ** ** | **102.6**                |        | 93.5     |       | 96.2     |       | 111.2    |       | 140.6    |       |
| Income Before Income Taxes                                                       | ** ** | **272.5**                |        | 308.9    |       | 268.8    |       | 268.4    |       | 236.4    |       |
| Income Taxes                                                                     | ** ** | **102.2**                |        | 119.9    |       | 102.5    |       | 105.2    |       | 93.3     |       |
| Net Income                                                                       | ** ** | **170.3**                |        | 189.0    |       | 166.3    |       | 163.2    |       | 143.1    |       |
| Preference Stock Dividends                                                       | ** ** | **13.2**                 |        | 13.2     |       | 13.2     |       | 13.2     |       | 13.2     |       |
| Earnings Applicable to Common Stock                                              | ** ** | **$**                    | **157.1**   |     | $          | 175.8    |       | $        | 153.1      |     | $          | 150.0 |   | $ | 129.9 |   |
| **Summary of Financial Condition**                                               | ** ** | ** **               |        |     |       |     |       |     |       |     |       |
| Total Assets                                                                     | ** ** | **$**                    | **5,140.7** |     | $          | 4,742.1  |       | $        | 4,662.9    |     | $          | 4,706.6 |   | $ | 4,779.9 |   |
| Current Portion of Long-Term Debt                                                | ** ** | **$**                    | **258.3**   |     | $          | 469.6    |       | $        | 165.9      |     | $          | 330.6 |   | $ | 420.7 |   |
| Capitalization                                                                   | ** ** | ** **               |        |     |       |     |       |     |       |     |       |
| Long-Term Debt                                                                   | ** ** | **$**                    | **1,480.5** |     | $          | 1,015.1  |       | $        | 1,359.5    |     | $          | 1,343.7 |   | $ | 1,499.1 |   |
| Minority Interest                                                                | ** ** | **16.7**                 |        | 18.3     |       | 18.7     |       | 18.9     |       | 19.4     |       |
| Preference Stock Not Subject to Mandatory Redemption                             | ** ** | **190.0**                |        | 190.0    |       | 190.0    |       | 190.0    |       | 190.0    |       |
| Common Shareholder’s Equity                                                 | ** ** | **1,651.5**              |        | 1,622.5  |       | 1,566.0  |       | 1,487.7  |       | 1,461.7  |       |
| Total Capitalization                                                             | ** ** | **$**                    | **3,338.7** |     | $          | 2,845.9  |       | $        | 3,134.2    |     | $          | 3,040.3 |   | $ | 3,170.2 |   |
| **Financial Statistics at Year End**                                             | ** ** | ** **               |        |     |       |     |       |     |       |     |       |
| Ratio of Earnings to Fixed Charges                                               | ** ** | **3.60**                 |        | 4.22     |       | 3.75     |       | 3.36     |       | 2.66     |       |
| Ratio of Earnings to Fixed Charges and Preferred and Preference Stock  Dividends | ** ** | **2.99**                 |        | 3.45     |       | 3.08     |       | 2.82     |       | 2.31     |       |

 

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**Item 7.Management’s Discussion and Analysis of Financial Condition and Results ofOperations**

**Introduction and Overview**

ConstellationEnergy Group, Inc. (Constellation Energy) is an energy company thatconducts its business through various subsidiaries including a merchant energybusiness and Baltimore Gas and Electric Company (BGE). We describe ouroperating segments in *Note 3*.

This report isa 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. Wediscuss our business in more detail in *Item1. 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 financialcondition and the results of operations for Constellation Energy and BGEincluding:

 ̈factorswhich affect our businesses,

 ̈ourearnings and costs in the periods presented,

 ̈changesin earnings and costs between periods,

 ̈sourcesof earnings,

 ̈impactof these factors on our overall financial condition,

 ̈expectedfuture expenditures for capital projects, and

 ̈expectedsources of cash for future capital expenditures.

As you read thisdiscussion and analysis, refer to our Consolidated Statements of Income, whichpresent the results of our operations for 2006, 2005, and 2004. We analyze andexplain the differences between periods in the specific line items of ourConsolidated Statements of Income.

We have organized our discussion and analysis as follows:

 ̈First,we discuss our strategy.

 ̈Wethen describe the business environment in which we operate including howregulation, weather, and other factors affect our business.

 ̈Next,we discuss our critical accounting policies. These are the accounting policiesthat are most important to both the portrayal of our financial condition andresults of operations and require management’s most difficult, subjective orcomplex judgment.

 ̈Wehighlight significant events that are important to understanding our results ofoperations and financial condition.

 ̈Wethen review our results of operations beginning with an overview of our totalcompany results, followed by a more detailed review of those results byoperating segment.

 ̈Wereview our financial condition addressing our sources and uses of cash,security ratings, capital resources, capital requirements, commitments, andoff-balance sheet arrangements.

 ̈Weconclude with a discussion of our exposure to various market risks.

**Strategy**

We are pursuing a strategy ofproviding energy and energy related services through our competitive supplyactivities and BGE, our regulated utility located in Maryland. Our merchantenergy business focuses on short-term and long-term purchases and sales of energy, capacity, and relatedproducts to various customers, including distribution utilities,municipalities, cooperatives, and industrial, commercial, and governmentalcustomers.

We obtain thisenergy through both owned and contracted supply resources. Our generation fleetis strategically located in deregulated markets and includes various fuel types,such as nuclear, coal, gas, oil, and renewable sources. In addition to owninggenerating facilities, we contract for power from other merchant providers,typically through power purchase agreements. We intend to remain diversifiedbetween regulated transmission and distribution and competitive supply. We willuse both our owned generation and our contracted generation to support ourcompetitive supply operations.

We are aleading national competitive supplier of energy. In our wholesale andcommercial and industrial retail marketing activities we are leveraging our recognizedexpertise in providing full requirements energy and energy-related services toenter markets, capture market share, and organically grow these businesses.Through the application of technology, intellectual capital, processimprovement, and increased scale, we are seeking to reduce the cost ofdelivering full requirements energy and energy related services and managingrisk.

We are alsoresponding proactively to customer needs by expanding the variety of productswe offer. Our wholesale competitive supply activities include a growingoperation that markets physical energy products and risk management andlogistics services to generators, distributors, producers of coal, natural gasand fuel oil, and other consumers.

We trade energyand energy-related commodities and deploy risk capital in the managementof our portfolio in order to earn additional returns. These activities aremanaged through daily value at risk and stop loss limits and liquidityguidelines.

Within ourretail competitive supply activities, we are marketing a broader array ofproducts and expanding our markets. Over time, we may consider integrating thesale of electricity and natural gas to provide one energy procurement solutionfor our customers.

Collectively,the integration of owned and contracted electric generation assets withorigination, fuel procurement, and risk management expertise, allows ourmerchant energy business to earn incremental margin and more effectively manageenergy and commodity price risk over geographic regions and over time. Ourfocus is on providing solutions to customers’ energy needs, and our wholesalemarketing, risk management, and trading operation adds value to our owned andcontracted generation assets by providing national market access, market infrastructure,real-time market intelligence, risk management and arbitrage opportunities, andtransmission and transportation expertise. Generation capacity supports ourwholesale marketing, risk management, and trading operation by providing asource of reliable power supply.

30

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To achieve ourstrategic objectives, we expect to continue to pursue opportunities that expandour access to customers and to support our wholesale marketing, riskmanagement, and trading operation with generation assets that have diversifiedgeographic, fuel, and dispatch characteristics. We also expect to grow throughbuying and selling a greater number of physical energy products and services tolarge energy customers. We expect to achieve operating efficiencies within ourcompetitive supply operation and our generation fleet by selling more productsthrough our existing sales force, benefiting from efficiencies of scale, addingto the capacity of existing plants, and making our business processes moreefficient.

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

Customerchoice, regulatory change, and energy market conditions significantly impactour business. In response, we regularly evaluate our strategies with thesegoals in mind: to improve our competitive position, to anticipate and adapt tothe business environment and regulatory changes, and to maintain a strongbalance sheet and investment-grade credit quality.

We are constantly reevaluating our strategies and might consider:

 ̈acquiringor developing additional generating facilities and gas properties to supportour merchant energy business,

 ̈mergersor acquisitions of utility or non-utility businesses or assets, and

 ̈saleof assets or one or more businesses.

**Business Environment**

With theevolving regulatory environment surrounding customer choice, increasingcompetition, and the growth of our merchant energy business, various factorsaffect our financial results. We discuss some of these factors in more detailin the *Item 1. Business—Competition*section. We also discuss these various factors in the *Forward Looking Statements* and *Item 1A. Risk Factors* sections.

Over the lastseveral years, the energy markets have been highly volatile with significantchanges in natural gas, power, oil, coal, and emission allowance prices. Thevolatility of the energy markets impacts our credit portfolio, and we continueto actively manage our credit portfolio to attempt to reduce the impact of apotential counterparty default. We discuss our customer (counterparty) creditand other risks in more detail in the *MarketRisk* section.

In addition, the volatility of the energy markets impacts our liquidityand collateral requirements. We discuss our liquidity in the *Financial Condition* section.

**Competition**

We facecompetition in the sale of electricity, natural gas, and coal in wholesaleenergy markets and to retail customers.

Various stateshave moved to restructure their electricity markets. The pace of deregulationin these states varies based on historical moves to competition and responsesto recent market events. While many states continue to support retailcompetition and industry restructuring, other states that were consideringderegulation have slowed their plans or postponed consideration. In addition,other states are reconsidering deregulation.

All BGEelectricity and gas customers have the option to purchase electricity and gasfrom alternate suppliers.

We discussmerchant competition in more detail in *Item1. Business—Competition* section.

The impacts of electric deregulation on BGE in Maryland are discussedin *Item 1. Business—Electric RegulatoryMatters and Competition* section.

**Regulation— SenateBill 1**

In June 2006, Senate Bill 1 was enacted, which, among otherthings:

 ̈  directsthe Maryland PSC to conduct a comprehensive review of Maryland’s deregulatedelectricity market, including the implications of requiring or allowingutilities to construct, acquire, or lease power generating facilities andalternative approaches to power procurement;

 ̈  expandsthe authority of the Maryland PSC to review acquisitions, dispositions, andfinancings by public service companies operating in Maryland; and

 ̈  directsMaryland’s taxing authority to consider whether property tax valuationmethodologies applied to power plants located in Maryland should be revised inlight of the values of those properties in a restructured electric industry.

Because SenateBill 1 requires additional decisions and proceedings by the Maryland PSC andother governmental authorities to implement and interpret many of its provisions,we cannot predict the ultimate impact of the legislation on us, BGE, or theenergy market in Maryland. The new legislation and its implementation throughapplicable regulatory proceedings could have a material adverse effect on our,or BGE’s, financial results. In addition, one or more parties may challenge incourt one or more provisions of Senate Bill 1. The outcome of any challengesand the uncertainty that could result cannot be predicted.

We discuss the provisions of Senate Bill 1 relating to residentialelectric customer rates in *Item 1. Business—ElectricRegulatory Matters and Competition* section.

**Regulation by theMaryland PSC**

In addition to electric restructuring, which is discussed in *Item 1. Business—Electric Regulatory Matters andCompetition* section, regulation by the Maryland PSC significantlyinfluences BGE’s businesses. The Maryland PSC determines the rates that BGE cancharge customers of its electric distribution and gas businesses. The MarylandPSC incorporates into BGE’s standard offer service rates the transmission ratesdetermined by the Federal Energy Regulatory Commission (FERC). BGE’s electricrates are unbundled in customer billings to show separate components fordelivery service (i.e. base rates), electric supply (commodity charge),transmission, a universal service surcharge, and certain taxes. The rates forBGE’s regulated gas business continue to consist of a delivery charge (baserate) and a commodity charge.

31

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***Base Rates***

Base rates arethe rates the Maryland PSC allows BGE to charge its customers for the cost ofproviding them delivery service, plus a profit. BGE has both electric baserates and gas base rates. Higher electric base rates apply during the summerwhen the demand for electricity is higher. Gas base rates are not affected byseasonal changes.

BGE may ask theMaryland PSC to increase base rates from time to time. The Maryland PSChistorically has allowed BGE to increase base rates to recover its utilityplant investment and operating costs, plus a profit. Generally, rate increasesimprove the earnings of our regulated business because they allow us to collectmore revenue. However, rate increases are normally granted based on historicaldata and those increases may not always keep pace with increasing costs. Otherparties may petition the Maryland PSC to decrease base rates.

In December 2005, the Maryland PSC issued an order granting BGE a$35.6 million annual increase in its gas base rates. In December 2006, theBaltimore City Circuit Court upheld the rate order. However, certain partieshave filed an appeal with the Court of Special Appeals. We cannot provideassurance that the Maryland PSC’s order will not be reversed in whole or partor that certain issues will not be remanded to the Maryland PSC forreconsideration.

***ElectricCommodity and Transmission Charges***

BGE electric commodity and transmission charges (standard offerservice), including the enactment of Senate Bill 1 in Maryland, arediscussed in *Item 1. Business—ElectricRegulatory Matters and Competition* section.

***Gas CommodityCharge***

BGE charges its gas customers separately for the natural gas theypurchase. The price BGE charges for the natural gas is based on a market-basedrates incentive mechanism approved by the Maryland PSC. We discuss market-basedrates in more detail in the *Regulated GasBusiness—Gas Cost Adjustments* section and in *Note 6.*

**Federal Regulation**

*FERC*

The FERC hasjurisdiction over various aspects of our business, including electrictransmission and wholesale natural gas and electricity sales. We believe thatFERC’s continued commitment to fair and efficient wholesale energy marketsshould continue to result in improvements to competitive markets across variousregions.

Since 1997,operation of BGE’s transmission system has been under the authority of PJMInterconnection (PJM), the Regional Transmission Organization (RTO) for theMid-Atlantic region, pursuant to FERC oversight. As the transmission operator,PJM operates the energy markets and conducts day-to-day operations of the bulkpower system. The liability of transmission owners, including BGE, and powergenerators is limited to those damages caused by the gross negligence of suchentities.

In addition toPJM, RTOs exist in other regions of the country such as the Midwest, New York,and New England. In addition to operation of the transmission system andresponsibility for transmission system reliability, these RTOs also operateenergy markets for their region pursuant to FERC’s oversight. Our merchantenergy business participates in these regional energy markets. These marketsare continuing to develop, and revisions to market structure are subject toreview and approval by FERC. We cannot predict the outcome of any reviews atthis time. However, changes to the structure of these markets could have amaterial effect on our financial results.

Ongoinginitiatives at FERC have included a review of its methodology for the grantingof market-based rate authority to sellers of electricity. FERC hasannounced interim tests that will be used to determine the extent to whichcompanies may have market power in certain regions. Where market power is foundto exist, FERC may require companies to implement measures to mitigate themarket power in order to maintain market-based rate authority. Inaddition, FERC is reviewing other aspects of its granting of market-basedrate authority, including horizontal and vertical market power, affiliate abuse,and barriers to entry. We cannot determine the eventual outcome of FERC’sefforts in this regard and their impact on our financial results at this time.

In November 2004,FERC eliminated through and out transmission rates between the MidwestIndependent System Operator (MISO) and PJM and put in place Seams EliminationCharge/Cost Adjustment/Assignment (SECA) transition rates, which are paid bythe transmission customers of MISO and PJM and allocated among the varioustransmission owners in PJM and MISO. The SECA transition rates were in effectfrom December 1, 2004 through March 31, 2006. FERC set for hearingthe various compliance filings that established the level of the SECA rates andhas indicated that the SECA rates are being recovered from the MISO and PJMtransmission customers subject to refund by the MISO and PJM transmissionowners.

In addition,FERC provided transmission customers that are charged the SECA rates with anopportunity to demonstrate that such charges should be shifted to their wholesalepower suppliers. We are a recipient of SECA payments, payer of SECA charges,and supplier to whom such charges may be shifted. Administrative hearingsregarding the SECA charges concluded in May 2006, and an initial decisionfrom the FERC administrative law judge (ALJ) was issued in August 2006. Thedecision of the ALJ generally found in favor of reducing the overall SECAliability. The decision, if upheld, is expected to significantly reduce theoverall SECA liability at issue in this proceeding. However, the ALJ alsoallowed SECA charges to be shifted to upstream suppliers, subject to certainadjustments. Therefore, certain charges could be shifted to our wholesalemarketing, risk management, and trading operation. This decision will bereviewed by FERC. We are unable to predict the timing or final outcome of FERC’sSECA rate proceeding. However, as the amounts collected under the SECA ratesare subject to refund and the ultimate outcome of the proceeding establishingSECA rates is uncertain, the result of this proceeding may have a materialeffect on our financial results.

In April 2006,FERC issued an initial order approving PJM’s proposal to restructure itscapacity market. Such a restructuring would change how we are paid forgenerating plant capacity available to PJM. However, FERC found that certainelements of the proposal needed further development before FERC could issue afinal order and encouraged the parties to the proceeding, includingConstellation Energy, to continue to seek a negotiated resolution of theremaining issues. Subsequently, 

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settlement discussions were conducted among the parties that resultedin a settlement being approved by FERC in December 2006, subject torequests for rehearing and potential further judicial review. Currently, wecannot predict with certainty the capacity prices that will result from therestructuring, given that rules must still be developed, or the possible effectsuch prices will have on our, or BGE’s, financial results. 

In February2007, FERC adopted Order No. 890, which reforms the open-access transmissionregulatory framework. We are in the process of evaluating this rule and itspossible effect on our, or BGE’s, financial results.

Other market changes are routinely proposed and considered on anongoing basis. Such changes will be subject to FERC’s review and approval. Wecannot predict the outcome of these proceedings or the possible effect on our,or BGE’s, financial results at this time.

***Federal EnergyLegislation***

The EnergyPolicy Act of 2005 (EPACT 2005) was enacted in August 2005. Thelegislation encourages investments in energy production and deliveryinfrastructure, including further development of competitive wholesale energymarkets, and promotes the use of a diverse mix of fuels and renewabletechnologies to generate electricity, including federal support and taxincentives for clean coal, nuclear, and renewable power generation. Effective February 2006,the legislation repealed the Public Utility Holding Company Act of 1935 (PUHCA1935).

In addition,EPACT 2005 significantly increased FERC’s enforcement authority.  There have been a number of FERC rulemakingproceedings that relate to the implementation of EPACT 2005 includingproceedings relating to FERC’s new responsibilities following the repeal ofPUHCA 1935, its revised merger authority, its new authority over electric gridreliability, and its new authority with respect to addressing electric and gasmarket manipulation. FERC has moved expeditiously to implement its newauthority under EPACT 2005 and has completed many of its rulemaking proceedingsunder EPACT 2005.  Additional rulemakingremains to be completed, which could have a material impact on our, or BGE’s,financial results.

There are also rulemakings required from other federal agencies, theoutcome of which could affect our financial results, but we cannot at this timepredict such outcome or the actual effect on our financial results.

**Weather**

***Merchant EnergyBusiness***

Weather conditions in the different regions of North America influencethe financial results of our merchant energy business. Weather conditions canaffect the supply of and demand for electricity, gas, and fuels. Changes inenergy supply and demand may impact the price of these energy commodities inboth the spot market and the forward market, which may affect our results inany given period. Typically, demand for electricity and its price are higher inthe summer and the winter, when weather is more extreme. The demand for andprice of natural gas and oil are higher in the winter. However, all regions ofNorth America typically do not experience extreme weather conditions at thesame time, thus we are not typically exposed to the effects of extreme weatherin all parts of our business at once.

***BGE***

Weather affects the demand for electricity and gas for our regulatedbusinesses. Very hot summers and very cold winters increase demand. Mildweather reduces demand. Weather affects residential sales more than commercialand industrial sales, which are mostly affected by business needs forelectricity and gas. The Maryland PSC approved a revenue decoupling mechanismwhich allows BGE to record a monthly adjustment to our regulated gas businessrevenues to eliminate the effect of abnormal weather patterns. We discuss thisfurther in the *Regulated Gas Business—RevenueDecoupling* section.

**Other Factors**

A number of other factors significantly influence the level andvolatility of prices for energy commodities and related derivative products forour merchant energy business. These factors include:

 ̈seasonal,daily, and hourly changes in demand,

 ̈numberof market participants,

 ̈extremepeak demands,

 ̈availablesupply resources,

 ̈transportationand transmission availability and reliability within and between regions,

 ̈locationof our generating facilities relative to the location of our load-servingobligations,

 ̈implementationof new market rules governing operations of regional power pools,

 ̈proceduresused to maintain the integrity of the physical electricity system duringextreme conditions,

 ̈changesin the nature and extent of federal and state regulations, and

 ̈internationalsupply and demand.

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

 ̈weatherconditions,

 ̈marketliquidity,

 ̈capabilityand reliability of the physical electricity and gas systems,

 ̈localtransportation systems, and

 ̈thenature and extent of electricity deregulation.

Other factorsalso impact the demand for electricity and gas in our regulated businesses.These factors include the number of customers and usage per customer during agiven period. We use these terms later in our discussions of regulated electricand gas operations. In those sections, we discuss how these and other factorsaffected electric and gas sales during the periods presented.

The number ofcustomers in a given period is affected by new home and apartment constructionand by the number of businesses in our service territory.

Usage per customer refers to all other items impacting customer salesthat cannot be measured separately. These factors include the strength of theeconomy in our service territory. When the economy is healthy and expanding,customers tend to consume more electricity and gas. Conversely, during aneconomic downturn, our customers tend to consume less electricity and gas.

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**EnvironmentalMatters and Legal Proceedings**

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

**AccountingStandards Adopted and Issued**

We discuss recently adopted and issued accounting standards in *Note 1*.

**Critical Accounting Policies**

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

 ̈ourreported amounts of revenues and expenses in our Consolidated Statements ofIncome,

 ̈ourreported amounts of assets and liabilities in our Consolidated Balance Sheets,and

 ̈ourdisclosure of contingent assets and liabilities.

These estimatesinvolve judgments with respect to numerous factors that are difficult topredict and are beyond management’s control. As a result, actual amounts couldmaterially differ from these estimates.

Management believes the following accounting policies representcritical accounting policies as defined by the Securities and ExchangeCommission (SEC). The SEC defines critical accounting policies as those thatare both most important to the portrayal of a company’s financial condition andresults of operations and require management’s most difficult, subjective, orcomplex judgment, often as a result of the need to make estimates about theeffect of matters that are inherently uncertain and may change in subsequentperiods. We discuss our significant accounting policies, including those thatdo not require management to make difficult, subjective, or complex judgmentsor estimates, in *Note 1*.

**Accounting forDerivatives**

Our merchantenergy business originates and acquires contracts for energy, other energy-relatedcommodities, and related derivatives. We record merchant energy businessrevenues using two methods of accounting: accrual accounting and mark-to-marketaccounting. The accounting requirements for derivatives are governed byStatement of Financial Accounting Standard (SFAS) No. 133, *Accounting for Derivative Instruments and HedgingActivities,***as amended,and applying those requirements involves the exercise of judgment in evaluatingthese provisions, as well as related implementation guidance and applying thoserequirements to complex contracts in a variety of commodities and markets.

Manyfundamental customer contracts in our business, such as those associated withour load-serving activities, must be accounted for on an accrual basis.  We may economically hedge these contracts withderivatives and elect cash-flow hedge accounting or apply the normal purchaseand normal sale exception in order to match more closely the timing of therecognition of earnings from these transactions.  We make these elections because we believethat accrual accounting provides the most transparent presentation to ourshareholders of these business activities. If our commercial transactions or related hedges meet the definition ofa derivative, we must comply with the provisions of SFAS No. 133 in order touse cash-flow hedge accounting or the normal purchase and normal saleexception.  Qualifying for either ofthese accounting treatments requires ongoing compliance with specific, detaileddocumentation and other requirements that may be unrelated to the economics ofthe transactions or how the associated risks are managed.  While we believe we have appropriate controlsin place to comply with these requirements, the failure to meet all of thoserequirements, even inadvertently, may result in disqualifying the use of theseaccounting treatments for those transactions for any affected period until allsuch requirements are satisfied.

The exercise ofmanagement’s judgment in using cash-flow hedge accounting or electing thenormal purchase and sale exception versus mark-to-market accounting, includingcompliance with all of the associated qualification and documentationrequirements, materially impacts our financial results with respect to timingof the recognition of earnings.   Inaddition, interpretations of SFAS No. 133 could continue to evolve.  If there is a future change in interpretationor a failure to meet the qualification and documentation requirements,contracts that currently are excluded from the provisions of SFAS No. 133 underthe normal purchase and normal sale exception or for which changes in fairvalue are recorded in other comprehensive income under cash-flow hedgeaccounting could be deemed to no longer qualify for those accountingtreatments.  If that were to occur,normal purchase and normal sale contracts could be required to be recorded onthe balance sheet at fair value with changes in value recorded in the incomestatement, and changes in value of derivatives previously designated ascash-flow hedges could be required to be recorded in the income statementrather than in other comprehensive income. 

We recordrevenues and fuel and purchased energy expenses from the sale or purchase ofenergy, energy-related products, and energy services under the accrualmethod of accounting in the period when we deliver or receive energycommodities, products, and services, or settle contracts. We use accrualaccounting for our merchant energy and other nonregulated businesstransactions, including the generation or purchase and sale of electricity,gas, and coal as part of our physical delivery activities and for power, gas,and coal sales contracts that are not subject to mark-to-market accounting.Contracts that are eligible for accrual accounting include non-derivativetransactions and derivatives that qualify for and are designated as normalpurchases and normal sales of commodities that will be physically delivered.

The use ofaccrual accounting requires us to analyze contracts to determine whether theyare non-derivatives or, if they are derivatives, whether they meet therequirements for designation as normal purchases and normal sales. For thosederivative contracts that do not meet these criteria, we may also analyzewhether they qualify for hedge accounting, including performing an evaluationof historical market price information to determine whether such contracts areexpected to be highly effective in offsetting changes in cash flows from therisk being hedged. We record the fair value of derivatives for which we have 

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elected hedge accounting in “Risk management assets and liabilities.”

We use themark-to-market method of accounting for derivative contracts for which we donot elect to use accrual accounting or hedge accounting. These mark-to-marketactivities include derivative contracts for energy and other energy-relatedcommodities. Under the mark-to-market method of accounting, we record the fairvalue of these derivatives as mark-to-market energy assets and liabilities atthe time of contract execution. We record the changes in mark-to-market energyassets and liabilities in our Consolidated Statements of Income.

Mark-to-marketenergy assets and liabilities consist of a combination of energy and energy-relatedderivative contracts. While some of these contracts represent commodities orinstruments for which prices are available from external sources, othercommodities and certain contracts are not actively traded and are valued usingmodeling techniques to determine expected future market prices, contractquantities, or both. The market prices and quantities used to determine fairvalue reflect management’s best estimate considering various factors. However,future market prices and actual quantities will vary from those used in recordingmark-to-market energy assets and liabilities, and it is possible that suchvariations could be material.

We recordvaluation adjustments to reflect uncertainties associated with certainestimates inherent in the determination of the fair value of mark-to-marketenergy assets and liabilities. The effect of these uncertainties is notincorporated in market price information or other market-based estimatesused to determine fair value of our mark-to-market energy contracts. To theextent possible, we utilize market-based data together with quantitativemethods for both measuring the uncertainties for which we record valuationadjustments and determining the level of such adjustments and changes in thoselevels.

We describe below the main types of valuation adjustments we record andthe process for establishing each. Generally, increases in valuationadjustments reduce our earnings, and decreases in valuation adjustmentsincrease our earnings. However, all or a portion of the effect on earnings ofchanges in valuation adjustments may be offset by changes in the value of theunderlying positions.

 ̈Close-outadjustment—represents the estimated cost to close out or sell to a third-partyopen mark-to-market positions. This valuation adjustment has the effect ofvaluing “long” positions (the purchase of a commodity) at the bid price and “short”positions (the sale of a commodity) at the offer price. We compute thisadjustment using a market-based estimate of the bid/offer spread for eachcommodity and option price and the absolute quantity of our net open positionsfor each year. The level of total close-out valuation adjustments increases aswe have larger unhedged positions, bid-offer spreads increase, or marketinformation is not available, and it decreases as we reduce our unhedgedpositions, bid-offer spreads decrease, or market information becomes available.To the extent that we are not able to obtain observable market information forsimilar contracts, the close-out adjustment is equivalent to the initialcontract margin, thereby resulting in no gain or loss at inception. In theabsence of observable market information, there is a presumption that thetransaction price is equal to the market value of the contract, and thereforewe do not recognize a gain or loss at inception. We recognize such gains orlosses in earnings as we realize cash flows under the contract or whenobservable market data becomes available.

 ̈Credit-spreadadjustment—for risk management purposes, we compute the value of ourmark-to-market energy assets and liabilities using a risk-free discount rate.In order to compute fair value for financial reporting purposes, we adjust thevalue of our mark-to-market energy assets to reflect the credit-worthinessof each counterparty based upon either published credit ratings, or equivalentinternal credit ratings and associated default probability percentages. Wecompute this adjustment by applying a default probability percentage to ouroutstanding credit exposure, net of collateral, for each counterparty. Thelevel of this adjustment increases as our credit exposure to counterpartiesincreases, the maturity terms of our transactions increase, or the creditratings of our counterparties deteriorate, and it decreases when our creditexposure to counterparties decreases, the maturity terms of our transactionsdecrease, or the credit ratings of our counterparties improve.

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

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

 ̈ourability to continue to designate and qualify derivative contracts for normalpurchase and normal sale accounting or hedge accounting under the requirementsof SFAS No. 133, as amended and as interpreted in supplementalguidance,

 ̈potentialvolatility in earnings from ineffectiveness associated with derivatives subjectto hedge accounting,

 ̈potentialvolatility in earnings from derivative contracts that serve as economic hedgesbut do not meet the accounting requirements to qualify for normal purchase andnormal sale accounting or hedge accounting,

 ̈ourability to enter into new mark-to-market derivative origination transactions,and

 ̈sufficientliquidity and transparency in the energy markets to permit us to record gainsat inception of new derivative contracts because fair value is evidenced byquoted market prices, current market transactions, or other observable marketinformation.

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As discussed in *Note 1,* the FinancialAccounting Standards Board (FASB) issued SFAS No. 157, *Fair Value Measurements*, which**iseffective January 1, 2008 and will affect our accounting for derivatives.SFAS No. 157 defines fair value, establishes a framework for measuringfair value, and expands disclosures for fair value measurements.

**Evaluation ofAssets for Impairment and Other Than Temporary Decline in Value**

*Long-LivedAssets*

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

 ̈asignificant decrease in the market price of a long-lived asset,

 ̈asignificant adverse change in the manner an asset is being used or its physicalcondition,

 ̈anadverse action by a regulator or legislature or an adverse change in thebusiness climate,

 ̈anaccumulation of costs significantly in excess of the amount originally expectedfor the construction or acquisition of an asset,

 ̈acurrent-period loss combined with a history of losses or the projectionof future losses, or

 ̈achange in our intent about an asset from an intent to hold to a greater than50% likelihood that an asset will be sold or disposed of before the end of itspreviously estimated useful life.

For long-livedassets that are expected to be held and used, SFAS No. 144 provides thatan impairment loss shall only be recognized if the carrying amount of an assetis not recoverable and exceeds its fair value. The carrying amount of an assetis not recoverable under SFAS No. 144 if the carrying amount exceeds thesum of the undiscounted future cash flows expected to result from the use andeventual disposition of the asset. Therefore, when we believe an impairmentcondition may have occurred, we are required to estimate the undiscountedfuture cash flows associated with a long-lived asset or group of long-livedassets at the lowest level for which identifiable cash flows are largely independentof the cash flows of other assets and liabilities. This necessarily requires usto estimate uncertain future cash flows.

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

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

For long-livedassets that can be classified as assets held for sale under SFAS No. 144,an impairment loss is recognized to the extent their carrying amount exceedstheir fair value less costs to sell.

If we determinethat the undiscounted cash flows from an asset to be held and used are lessthan the carrying amount of the asset, or if we have classified an asset asheld for sale, we must estimate fair value to determine the amount of anyimpairment loss. The estimation of fair value under SFAS No. 144, whetherin conjunction with an asset to be held and used or with an asset held forsale, also involves judgment. We consider quoted market prices in activemarkets to the extent they are available. In the absence of such information,we may consider prices of similar assets, consult with brokers, or employ othervaluation techniques. Often, we will discount the estimated future cash flowsassociated with the asset using a single interest rate that is commensuratewith the risk involved with such an investment or employ an expected presentvalue method that probability-weights a range of possible outcomes. Theuse of these methods involves the same inherent uncertainty of future cashflows as discussed above with respect to undiscounted cash flows. Actual futuremarket prices and project costs could vary from those used in our estimates,and the impact of such variations could be material.

We are alsorequired to evaluate our equity-method and cost-method investments (forexample, in partnerships that own power projects) to determine whether or notthey are impaired. Accounting Principles Board (APB) Opinion No. 18, *The Equity Method of Accounting for Investments inCommon Stock*, provides the accounting requirements for theseinvestments. The standard for determining whether an impairment must berecorded under APB No. 18 is whether the investment has experienced a lossin value that is considered an “other than a temporary” decline in value.

The evaluation and measurement of impairments under the APB No. 18standard involves the same uncertainties as described above for long-livedassets that we own directly and account for in accordance with SFASNo. 144. Similarly, the estimates that we make with respect to our equityand cost-method investments are subject to variation, and the impact of suchvariations could be material. Additionally, if the projects in which we holdthese investments recognize an impairment under the provisions of SFASNo. 144, we would record our proportionate share of that impairment lossand would evaluate our investment for an other than temporary decline in valueunder APB No. 18.

*Gas Properties*

We evaluate unproved property at least annually to determine if it isimpaired under SFAS No. 19, *FinancialAccounting and Reporting by Oil and Gas Producing Properties*.Impairment for unproved property occurs if there are no firm plans to continuedrilling, lease expiration is at risk, or historical experience necessitates avaluation allowance.

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*Debt and EquitySecurities*

Our investments in debt and equity securities, primarily our nucleardecommissioning trust fund assets, are subject to impairment evaluations underFASB Staff Position SFAS 115-1 and SFAS 124-1(FSP 115-1 and 124-1), *TheMeaning of Other-Than-Temporary Impairment and Its Application to CertainInvestments.* FSP 115-1 and 124-1 requires us todetermine whether a decline in fair value of an investment below the amortizedcost basis is other than temporary. If we determine that the decline in fairvalue is judged to be other than temporary, the cost basis of the investmentmust be written down to fair value as a new cost basis.

*Goodwill*

Goodwill is the excess of the purchase price of an acquired businessover the fair value of the net assets acquired. We account for goodwill andother intangibles under the provisions of SFAS No. 142, *Goodwill and Other Intangible Assets*. Wedo not amortize goodwill. SFAS No. 142 requires us to evaluate goodwillfor impairment at least annually or more frequently if events and circumstancesindicate the business might be impaired. Goodwill is impaired if the carryingvalue of the business exceeds fair value. Annually, we estimate the fair valueof the businesses we have acquired using techniques similar to those used toestimate future cash flows for long-lived assets as discussed on the previouspage, which involves judgment. If the estimated fair value of the business isless than its carrying value, an impairment loss is required to be recognizedto the extent that the carrying value of goodwill is greater than its fairvalue.

**Asset RetirementObligations**

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

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

Our nuclear decommissioning costs represent our largest assetretirement obligation. This obligation primarily results from the requirementto decommission and decontaminate our nuclear generating facilities inconnection with their future retirement. We utilize site-specificdecommissioning cost estimates to determine our nuclear asset retirementobligations. However, given the magnitude of the amounts involved, complicatedand ever-changing technical and regulatory requirements, and the very long timehorizons involved, the actual obligation could vary from the assumptions usedin our estimates, and the impact of such variations could be material.

**Significant Events**

**Termination ofMerger Agreement with FPL Group, Inc.**

On October 24, 2006, Constellation Energy and FPL Group, Inc.(FPL Group) agreed to terminate the Agreement and Plan of Merger the partieshad entered into on December 18, 2005. We discuss the merger termination agreement in more detail in *Note 15*.

**Commodity Prices**

During 2006, we continued to experience significant changes incommodity prices. This volatile commodity price environment continues to impactour results of operations and financial conditions. This volatility contributedto the following changes in our financial statements:

 ̈  totalmark-to-market assets decreased $510.3 million and total mark-to-marketliabilities decreased $796.9 million since December 31, 2005,

 ̈  totalrisk management assets decreased $1,282.9 million and total riskmanagement liabilities increased $528.3 million since December 31,2005,

 ̈  netcash collateral requirements increased $630.6 million since December 31,2005,

 ̈  accumulatedother comprehensive loss increased $1,088.1 million since December 31,2005,

 ̈  totalrevenues increased $2,316.6 million during 2006 compared to 2005, and

 ̈  totalfuel and purchased energy expenses increased $1,691.1 million during 2006compared to 2005.

We discuss the impact of commodity prices on our financial conditionand results of operations in more detail in the following sections:

 ̈  *Merchant Energy Results,*

 ̈  *Financial Condition,*

 ̈  *Contractual Payment Obligations and Committed Amounts, and*

 ̈  *Market Risk.*

**ResidentialElectric Rates**

We discuss Senate Bill 1 enacted by the Maryland General Assemblyin more detail in the *Item1. Business—Electric Regulatory Matters and Competition* and *Regulation*sections.

**Gas-Fired Plants**

In December 2006, we completed the sale of several gas-firedplants for $1.6 billion in cash, and recognized a pre-tax gain onthe sale of $259.0 million, or $163.8 million after-tax. We discuss the sale inmore detail in *Note 2*.

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**Synthetic FuelFacilities**

Our merchant energy business hasinvestments in facilities that manufacture solid synthetic fuel produced fromcoal as defined under the Internal Revenue Code (IRC) for which we can claimtax credits on our Federal income tax return through 2007. The IRC provides fora phase-out of synthetic fuel tax credits if average annual wellhead oil pricesincrease above certain levels. For 2006, we estimate the tax credit reductionwould begin if the reference price exceeds approximately $55 per barrel andwould be fully phased-out if the reference price exceeds approximately $68 perbarrel. We discuss how we determine the amount of phase-out in more detail in *Note 10.*

Based onmonthly EIA published wellhead oil prices for the ten months ended October 31,2006 and November and December NYMEX prices for light, sweet, crude oil(adjusted for the 2006 difference between EIA and NYMEX prices), we estimate a38% tax credit phase-out in 2006. We recorded the effect of this phase-out estimateas a reduction in tax credits of $44.3 million during 2006.

For 2007, weestimate the tax credit reduction would begin if the reference price exceedsapproximately $56 per barrel and would be fully phased-out if the referenceprice exceeds approximately $70 per barrel. Based on forward market prices andvolatilities as of February 22, 2007, we estimate a 21% tax creditphase-out in 2007. However, the ultimate amount of tax credits phased-out for2007 is subject to change based on the actual reference price and productionlevels for the entire year. In addition, our ability to claim synthetic fueltax credits and the potential phase-out of these credits could be materiallyimpacted by any future legislative changes to the Internal Revenue Code.

We activelymonitor and manage our exposure to synthetic fuel tax credit phase-out as partof our ongoing hedging activities. In addition, we continue to monitor variousoptions related to our South Carolina facility, including the suspension orcessation of synthetic fuel production depending on our expectation of thelevel of tax credit phase-out.

We will continue to monitor the level of synthetic fuel tax creditphase-out based on forward market prices and volatilities and performimpairment analyses as warranted. A significant increase in synthetic fuel taxcredit phase-out could result in an impairment. At December 31, 2006, thebook value of our investment in synthetic fuel facilities is approximately $14million, substantially all of which is related to our South Carolina facility.

**Workforce ReductionCosts**

During the quarter ended March 31,2006, we incurred costs associated with a planned workforce restructuring atour R. E. Ginna Nuclear Power Plant (Ginna). In July 2006, weannounced a planned workforce restructuring at our Nine Mile Point NuclearStation (Nine Mile Point). We also initiated a restructuring of the workforceat our Calvert Cliffs nuclear facility during the third quarter of 2006.

In addition, during 2006,we recorded a settlement charge in our Consolidated Statements of Income forone of our qualified plans under SFAS No. 88, *Employers’ Accounting for Settlements and Curtailments of DefinedBenefit Pension Plans and for Termination Benefits*.

We discuss these restructurings and the settlement charge in moredetail in *Note 2.*

**Acquisitions**

During 2006, we acquired working interests in gas and oil producingfields. We discuss this acquisition in more detail in the *Note 15*.

**Initial PublicOffering of Constellation Energy Partners LLC**

In November 2006,Constellation Energy Partners LLC (CEP), a limited liability company formed byConstellation Energy, completed its initial public offering of common units.CEP is principally engaged in the acquisition, development, and exploitation ofnatural gas properties. CEP’s existing property is located in the Robinson’sBend Field in the Black Warrior Basin of Alabama.

We discuss the impact of this initial public offering on our financialresults in more detail in *Note 2*.

**NineMile Point License Extension**

In October 2006, we received Nuclear Regulatory Commissionapproval for license extension for both units at our Nine Mile Point nuclearfacility. With the renewed licenses, we can continue to operate Unit 1 until2029 and Unit 2 until 2046.

**GinnaUprate**

During the fourth quarter of 2006, we completed a planned outage at ourGinna nuclear facility, which included an uprate of the plant from 498megawatts to 581 megawatts. We expect that the increase in capacity of thefacility will result in higher revenues in future years due to highergeneration.

**DividendIncrease**

In January 2007, we announced an increase in our quarterlydividend to $0.435 per share on our common stock. This is equivalent to anannual rate of $1.74 per share. Previously, our quarterly dividend on ourcommon stock was $0.3775 per share, equivalent to an annual rate of $1.51 pershare.

38

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**Resultsof Operations**

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

**Overview**

***Results***
| ** **                                                                                           | ** ** | **2006**                                 | ** ** | **2005**   | ** ** | **2004** | ** ** |
|------------------------------------------------------------------------------------------------------|------------|------------------------------------------|------------|------------|------------|----------|------------|
| ** **                                                                                           | ** ** | ***(In millions, after-tax)*** | ** ** |
| Merchant energy                                                                                      | ** ** | **$**                                    | **580.1**  | ** ** | $          | 359.4    |       | $ | 358.0 | ** ** |
| Regulated electric                                                                                   | ** ** | **120.2**                                |       | 149.4      |       | 131.1    |       |
| Regulated gas                                                                                        | ** ** | **37.0**                                 |       | 26.7       |       | 22.2     |       |
| Other nonregulated                                                                                   | ** ** | **11.3**                                 |       | 0.4        |       | (12.9    | )          |
| Income from continuing operations and before cumulative effects of  changes in accounting principles | ** ** | **748.6**                                |       | 535.9      |       | 498.4    |       |
| Income from discontinued  operations                                                                 | ** ** | **187.8**                                |       | 94.4       |       | 41.3     |       |
| Cumulative effects of  changes in accounting principles                                              |       | —                                   |       | (7.2       | )          | —   |       |
| Net Income                                                                                           | ** ** | **$**                                    | **936.4**  |       | $          | 623.1    |       | $ | 539.7 |   |
| *Other Items Included in Operations:*                                                                | * *   | * *                                 | * *   | * *   | * *   | * * | * *   |
| Gain on sale of gas-fired  plants                                                                    | ** ** | **$**                                    | **47.1**   |       | $          | —   |       | $ | — |   |
| Non-qualifying  hedges                                                                               | ** ** | **39.2**                                 |       | (24.9      | )          | 0.2      |       |
| Workforce reduction costs                                                                            | ** ** | **(17.0**                                | **)**      | (2.6       | )          | (5.9     | )          |
| Merger-related  costs                                                                                | ** ** | **(5.7**                                 | **)**      | (15.6      | )          | —   |       |
| Recognition of 2003  synthetic fuel tax credits                                                      | ** ** | **—**                               |       | —     |       | 35.9     |       |
| Total Other Items                                                                                    | ** ** | **$**                                    | **63.6**   |       | $          | (43.1    | )          | $ | 30.2 |   |

 

*Certain prior-year amounts have beenreclassified to conform with the current year’s presentation.*

**2006**

Our total netincome for 2006 increased $313.3 million, or $1.69 per share, compared to2005 mostly because of the following:

 ̈  We had higher earnings ofapproximately $144 million after-tax at our merchant energy business due tohigher gross margin from the Mid-Atlantic Region. We discuss this increase ingross margin in more detail in the *Mid-AtlanticRegion* section.

 ̈  We had higher earnings fromdiscontinued operations of $93.4 million after-tax mostly due to the gain onsale of our High Desert facility. In addition, we had higher earnings of $47.1million resulting from the recognition of a gain on sale of five othergas-fired generating facilities. We discuss the sale of these plants in moredetail in *Note 2.*

 ̈  We had higher wholesalecompetitive supply gross margin of approximately $105 million after-tax.This increase was partially offset by approximately $68 million after-taxof higher operating expenses mostly because of higher labor and benefit costsdue to the growth of our wholesale competitive supply operation. We discuss ourmark-to-market and wholesale accrual results in more detail in the *Competitive Supply* section.

 ̈  We had higher earnings of$67.7 million after-tax at our retail competitive supply operationprimarily due to an increase in gross margin, partially offset by higheroperating expenses to support the growth of this operation. We discuss ourretail gross margin in more detail in the *CompetitiveSupply—Retail* section.

 ̈  We had higher earnings ofapproximately $18 million after-tax due to the gain on the CEP initial publicoffering. This gain was partially offset by cash-flow hedge losses ofapproximately $10 million after-tax reclassified from “Accumulated othercomprehensive income” to revenues as a result of the initial public offering.We discuss the CEP transaction in more detail in *Note 2*.

 ̈  We had higher earnings of$10.3 million after-tax from our regulated gas business primarily due tothe favorable impact of the increase in gas base rates that was approved in December 2005.

These increaseswere partially offset by the following:

 ̈  We had lower earnings of$30.1 million after-tax at our synthetic fuel facilities mostly due to theexpected phase-out of tax credits as a result of the high price of oil. Wediscuss the phase-out of tax credits in more detail in the *Significant Events* section.

 ̈  We had lower earnings of$29.2 million after-tax from our regulated electric business primarily dueto higher operations and maintenance expenses and lower revenues lesselectricity purchased for resale expenses.

 ̈  We had lower earnings of$14.4 million after-tax due to workforce reduction costs associated withworkforce restructurings at our nuclear generating facilities. We discuss thesecosts in more detail in the *Note 2*.

 ̈  We had lower earnings ofapproximately $11 million after-tax due to higher fixed charges and lower otherincome. We discuss these items in more detail in the *Consolidated Nonoperating Income and Expenses* section.

**2005**

Our total netincome for 2005 increased $83.4 million, or $0.35 per share, compared to2004 mostly because of the following:

 ̈  Wehad higher earnings of approximately $58 million at our wholesalemarketing, risk management, and trading operation. This increase is primarilydue to the realization of higher gross margin, which included the terminationor restructuring of several energy contracts and higher mark-to-market resultsin earnings. We discuss these terminations, restructurings, and mark-to-marketresults in more detail in the *CompetitiveSupply* section. This increase in earnings was partially offset byhigher load-serving costs resulting from extreme weather and volatile commodityprices and higher operating expenses.

 ̈  Werecorded higher income from discontinued operations of $53.1 millionafter-tax. This increase is primarily due to a loss of $49.1 million aftertax in 2004 related to the sale of our Hawaiian geothermal facility which had anegative impact in that period. We discuss discontinued operations in moredetail in *Note 2.*

39

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 ̈  Wehad higher earnings of approximately $34 million after-tax primarily due tohigher interest and investment income due to a higher cash balance, and higherdecommissioning trust asset earnings, and lower interest expense resulting fromthe maturity of $300.0 million in long-term debt in 2005 and the favorableimpact of floating-rate swaps.

 ̈  Wehad higher earnings of $29.1 million after-tax at our Nine Mile Point andGinna facilities primarily due to productivity improvements and cost savinginitiatives partially offset by inflationary cost increases and costsassociated with the planned refueling outage at Ginna.

 ̈  Wehad higher earnings of $22.8 million after-tax at our regulated businessesprimarily due to favorable weather during 2005 compared to 2004.

 ̈  Wehad higher earnings of approximately $17 million after-tax due to the absenceof coal delivery issues that were experienced in 2004 that had a negativeimpact in that period.

 ̈  Wehad higher earnings from our other nonregulated businesses of$13.3 million after-tax, including higher gains from the continuedliquidation of our non-core investments and the results of Cogenex, which wasacquired in April 2005. We discuss the acquisition of Cogenex in moredetail in *Note 15*.

 ̈  Wehad higher earnings at our South Carolina synthetic fuel facility of$7.6 million after-tax due to a higher level of production in 2005compared to 2004.

These increaseswere partially offset by the following:

 ̈  Ourmerchant energy business recognized $35.9 million of 2003 synthetic fueltax credits in 2004 which had a positive impact in that period.

 ̈  Wehad lower earnings at our retail competitive supply operation of$25.1 million after-tax primarily due to higher costs to serve our loadobligations in Texas and the absence of bankruptcy settlements that had afavorable impact in 2004.

 ̈  Wehad lower earnings of $25.1 million after-tax related to losses associatedwith certain economic hedges that do not qualify for cash-flow hedge accountingtreatment. We discuss these economic hedges in more detail in the *Mark-to-Market* section.

 ̈  Wehad lower earnings of $15.6 million after-tax due to external costsassociated with the execution of our merger agreement with FPL Group.

 ̈  Wehad lower earnings of $20.0 million after-tax due to lower competitivetransition charge (CTC) revenues at our merchant energy business.

 ̈  Wehad lower earnings of $8.5 million after-tax related to the impact ofexpensing stock options during the fourth quarter of 2005.

 ̈  Wehad lower earnings of $7.2 million after-tax due to the cumulative effectof adopting FIN 47 and SFAS No. 123 Revised (SFAS No. 123R), *Share-Based Payment*. We discuss theadoption of these standards in detail in *Note 1*.

Earnings pershare was impacted by additional dilution, including the issuance of6.0 million shares of common stock on July 1, 2004.

**Merchant Energy Business**

*Background*

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

Our merchant energy business focuses ondelivery of physical, customer-oriented products to producers andconsumers, manages the risk and optimizes the value of our owned generationassets, and uses our portfolio management and trading capabilities both tomanage risk and to deploy risk capital to generate additional returns. Wecontinue to identify and pursue opportunities which can generate additionalreturns through portfolio management and trading activities within ourbusiness. These opportunities have increased due to the significant growth inscale of our competitive supply operations.

We recordmerchant energy revenues and expenses in our financial results in differentperiods depending upon which portion of our business they affect. We discussour revenue recognition policies in the *CriticalAccounting Policies* section and in *Note 1*.We summarize our revenue and expense recognition policies as follows:

 ̈  Werecord revenues as they are earned and fuel and purchased energy expenses asthey are incurred for contracts and activities subject to accrual accounting,including certain load-serving activities.

 ̈  Priorto the settlement of the forecasted transaction being hedged, we record changesin the fair value of contracts designated as cash-flow hedges in othercomprehensive income to the extent that the hedges are effective. We record theeffective portion of the changes in fair value of hedges in earnings in theperiod the settlement of the hedged transaction occurs. We record theineffective portion of the changes in fair value of hedges, if any, in earningsin the period in which the change occurs.

 ̈  Werecord changes in the fair value of contracts that are subject tomark-to-market accounting in revenues or fuel and purchased energy expenses inthe period in which the change occurs.

Mark-to-market accounting requires us to makeestimates and assumptions using judgment in determining the fair value ofcertain contracts and in recording revenues from those contracts. We discussthe effects of mark-to-market accounting on our results in the *Competitive Supply—Mark-to-Market* section.We discuss mark-to-market accounting and the accounting policies for themerchant energy business further in the *CriticalAccounting Policies* section and in *Note 1*.

Our wholesalemarketing, risk management, and trading operation actively transacts in energyand energy-related commodities in order to manage our portfolio of energypurchases and sales to customers through structured transactions. As part ofthese activities we trade energy and energy-related commodities anddeploy risk capital in the management of our portfolio in order to earnadditional returns. These activities are managed through daily value at riskand stop loss limits and liquidity guidelines, and may have a material impacton our financial results. We discuss the impact of our trading activities andvalue at risk in more detail in the *CompetitiveSupply—Mark-to-Market* and *MarketRisk* sections.

40

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***Results***
| ** **                                                                                                       | ** ** | **2006**                 | ** **   | **2005**  | ** ** | **2004** | ** ** |
|------------------------------------------------------------------------------------------------------------------|------------|--------------------------|--------------|-----------|------------|----------|------------|
| ** **                                                                                                       | ** ** | ***(In millions)*** | ** **   |
| Revenues                                                                                                         | ** ** | **$**                    | **17,166.2** |      | $          | 14,622.4 |       | $ | 10,188.3 |   |
| Fuel and purchased energy expenses                                                                               | ** ** | **(14,256.3**            | **)**        | (12,301.8 | )          | (8,118.1 | )          |
| Operating expenses                                                                                               | ** ** | **(1,549.4**             | **)**        | (1,346.1  | )          | (1,149.9 | )          |
| Workforce reduction costs                                                                                        | ** ** | **(28.2**                | **)**        | (4.4      | )          | (9.7     | )          |
| Merger-related transaction costs                                                                                 | ** ** | **(13.1**                | **)**        | (11.2     | )          | —   |       |
| Depreciation, depletion, and amortization                                                                        | ** ** | **(258.7**               | **)**        | (250.4    | )          | (221.9   | )          |
| Accretion of asset retirement obligations                                                                        | ** ** | **(67.6**                | **)**        | (62.0     | )          | (53.1    | )          |
| Taxes other than income taxes                                                                                    | ** ** | **(120.0**               | **)**        | (106.7    | )          | (83.3    | )          |
| Gain on sale of gas-fired plants                                                                                 | ** ** | **73.8**                 |         | —    |       | —   |       |
| Income from Operations                                                                                           | ** ** | **$**                    | **946.7**    |      | $          | 539.8    |       | $ | 552.3 |   |
| Income from continuing operations and before cumulative effects of  changes in accounting principles (after-tax) | ** ** | **$**                    | **580.1**    |      | $          | 359.4    |       | $ | 358.0 |   |
| Income from discontinued  operations (after-tax)                                                                 | ** ** | **186.9**                |         | 73.8      |       | 31.9     |       |
| Cumulative effects of changes in  accounting principles (after-tax)                                              |       | —                   |         | (7.4      | )          | —   |       |
| Net Income                                                                                                       | ** ** | **$**                    | **767.0**    |      | $          | 425.8    |       | $ | 389.9 |   |
| *Other Items Included in Operations (after-tax)*                                                                 | ** ** | ** **               |         |      |       |     |       |
| Gain on sale of gas-fired plants                                                                                 | ** ** | **$**                    | **47.1**     |      | $          | —   |       | $ | — |   |
| Non-qualifying hedges                                                                                            | ** ** | **39.2**                 |         | (24.9     | )          | 0.2      |       |
| Merger-related costs                                                                                             | ** ** | **(4.3**                 | **)**        | (10.4     | )          | —   |       |
| Workforce reduction costs                                                                                        | ** ** | **(17.0**                | **)**        | (2.6      | )          | (5.9     | )          |
| Recognition of 2003 synthetic  fuel tax credits                                                                  | ** ** | **—**               |         | —    |       | 35.9     |       |
| Total Other Items                                                                                                | ** ** | **$**                    | **65.0**     |      | $          | (37.9    | )          | $ | 30.2 |   |

 

*Certain prior-yearamounts have been reclassified to conform with the current year’s presentation.Above amounts include intercompany transactions eliminated in our ConsolidatedFinancial Statements. Note 3 provides a reconciliation of operatingresults by segment to our Consolidated Financial Statements.*

***Revenues andFuel and Purchased Energy Expenses***

Our merchantenergy business manages the revenues we realize from the sale of energy to ourcustomers and our costs of procuring fuel and energy. As previously discussed,our merchant energy business uses either accrual or mark-to-market accountingto record our revenues and expenses. Mark-to-market results reflect the netimpact of amounts recorded in either revenues or fuel and purchased energyexpenses to recognize changes in fair value of derivative contracts subject tomark-to-market accounting during the reporting period.

The differencebetween revenues and fuel and purchased energy expenses, including all directexpenses, is the gross margin of our merchant energy business, and this measureis a useful tool for assessing the profitability of our merchant energybusiness. Accordingly, we believe it is appropriate to discuss the operatingresults of our merchant energy business by analyzing the changes in grossmargin between periods. In managing our portfolio, we may terminate,restructure, or acquire contracts. Such transactions are within the normalcourse of managing our portfolio and may materially impact the timing of ourrecognition of revenues, fuel and purchased energy expenses, and cash flows.

We analyze our merchant energy gross margin in the following categoriesbecause of the risk profile of each category, differences in the revenuesources, and the nature of fuel and purchased energy expenses. With theexception of a portion of our competitive supply activities that we arerequired to account for using the mark-to-market method of accounting, all ofthese activities are accounted for on an accrual basis.

 ̈  Mid-AtlanticRegion—our fossil, nuclear, and hydroelectric generating facilities andload-serving activities in the PJM Interconnection (PJM) region. This alsoincludes active portfolio management of the generating assets and otherphysical and financial contractual arrangements, as well as other PJMcompetitive supply activities. In addition, due to the expiration of its powerpurchase agreement, beginning in June 2006 until its sale inDecember 2006, the results of our University Park generating facility areincluded with the Mid-Atlantic Region. University Park was previously includedin Plants with Power Purchase Agreements.

 ̈  Plantswith Power Purchase Agreements—our generating facilities outside theMid-Atlantic Region with long-term power purchase agreements. As discussed in *Note 2*, the**sale of theHigh Desert facility resulted in a reclassification of its results ofoperations to discontinued operations.

 ̈  WholesaleCompetitive Supply—our marketing, risk management, and trading operation thatprovides energy products and services primarily to distribution utilities,power generators, and other wholesale customers. We also provide global energyand related services and upstream and downstream natural gas services.

 ̈  RetailCompetitive Supply—our operation that provides electric and gas energy productsand services to commercial, industrial, and governmental customers.

 ̈  Other—ourinvestments in qualifying facilities and domestic power projects and ourgeneration operations and maintenance services.

In December 2006, we completed the saleof these gas-fired plants:
| **Facility**    | ** ** | **Capacity  (MW)** | ** ** | **Unit Type** | ** ** | **Location**   | ** ** |
|-----------------|------------|--------------------|------------|--------------------|------------|----------------|------------|
| High Desert     |       |               | 830        |               |       | Combined Cycle |       | California |   |
| Rio Nogales     |       |               | 800        |               |       | Combined Cycle |       | Texas |   |
| Holland         |       |               | 665        |               |       | Combined Cycle |       | Illinois |   |
| University Park |       |               | 300        |               |       | Peaking        |       | Illinois |   |
| Big Sandy       |       |               | 300        |               |       | Peaking        |       | West Virginia |   |
| Wolf Hills      |       |               | 250        |               |       | Peaking        |       | Virginia |   |

 

We discuss thesale of these gas-fired generating facilities in *Note 2.*

41

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We provide a summary of our revenues, fueland purchased energy expenses, and gross margin as follows:
| ** **                              | ** ** | **2006**                                                                                                      | ** **    | ** **      | ** ** | **2005**                 | ** ** | ** **      | ** ** | **2004**                 | ** ** | ** **      | ** ** |
|-----------------------------------------|------------|---------------------------------------------------------------------------------------------------------------|---------------|-----------------|------------|--------------------------|------------|-----------------|------------|--------------------------|------------|-----------------|------------|
| ** **                              | ** ** | ***          (Dollar amounts in millions)*** | ** **    | ** **      | ** ** |
| **Revenues:**                           | ** ** | ** **                                                                                                    | ** **    | ** **      | ** ** | ** **               | ** ** | ** **      | ** ** | ** **               | ** ** | ** **      | ** ** |
| Mid-Atlantic Region                     | ** ** | **$**                                                                                                         | **2,813.5**   |            |       |                     | $          | 2,283.9         |       |                     |       | $               | 1,925.6    |   |   |   |
| Plants with Power  Purchase Agreements  | ** ** | **650.5**                                                                                                     |          |            |       | 665.9                    |       |            |       | 555.3                    |       |            |       |
| Competitive Supply                      |       |                                                                                                          |          |            |       |                     |       |            |       |                     |       |            |       |
| Retail                                  | ** ** | **8,014.7**                                                                                                   |          |            |       | 6,942.3                  |       |            |       | 4,280.0                  |       |            |       |
| Wholesale                               | ** ** | **5,612.7**                                                                                                   |          |            |       | 4,672.3                  |       |            |       | 3,353.8                  |       |            |       |
| Other                                   | ** ** | **74.8**                                                                                                      |          |            |       | 58.0                     |       |            |       | 73.6                     |       |            |       |
| Total                                   | ** ** | **$**                                                                                                         | **17,166.2**  |            |       |                     | $          | 14,622.4        |       |                     |       | $               | 10,188.3   |   |   |   |
| **Fuel and purchased energy expenses:** | ** ** | ** **                                                                                                    | ** **    | ** **      | ** ** | ** **               | ** ** | ** **      | ** ** | ** **               | ** ** | ** **      | ** ** |
| Mid-Atlantic Region                     | ** ** | **$**                                                                                                         | **(1,727.6**  | **)**           |       |                     | $          | (1,436.5        | )          |                     |       | $               | (946.9     | ) |   |   |
| Plants with Power  Purchase Agreements  | ** ** | **(67.9**                                                                                                     | **)**         |            |       | (72.5                    | )          |            |       | (46.4                    | )          |            |       |
| Competitive Supply                      |       |                                                                                                          |          |            |       |                     |       |            |       |                     |       |            |       |
| Retail                                  | ** ** | **(7,570.2**                                                                                                  | **)**         |            |       | (6,668.2                 | )          |            |       | (4,011.4                 | )          |            |       |
| Wholesale                               | ** ** | **(4,890.6**                                                                                                  | **)**         |            |       | (4,124.6                 | )          |            |       | (3,113.4                 | )          |            |       |
| Other                                   |       | —                                                                                                        |          |            |       | —                   |       |            |       | —                   |       |            |       |
| Total                                   | ** ** | **$**                                                                                                         | **(14,256.3** | **)**           |       |                     | $          | (12,301.8       | )          |                     |       | $               | (8,118.1   | ) |   |   |
| ** **                              | ** ** | ** **                                                                                                    | ** **    | **% of  Total** | ** ** | ** **               | ** ** | **% of  Total** | ** ** | ** **               | ** ** | **% of  Total** | ** ** |
| **Gross margin:**                       | ** ** | ** **                                                                                                    | ** **    | ** **      | ** ** | ** **               | ** ** | ** **      | ** ** | ** **               | ** ** | ** **      | ** ** |
| Mid-Atlantic Region                     | ** ** | **$ 1,085.9**                                                                                            | ** **    | **37**          | **%**      | $   847.4 |       | 36              | %          | $   978.7 |       | 47              | %          |
| Plants with Power  Purchase Agreements  | ** ** | **582.6**                                                                                                     | ** **    | **20**          |       | 593.4                    |       | 25              |       | 508.9                    |       | 25              |       |
| Competitive Supply                      |       |                                                                                                          |          |            |       |                     |       |            |       |                     |       |            |       |
| Retail                                  | ** ** | **444.5**                                                                                                     | ** **    | **15**          |       | 274.1                    |       | 12              |       | 268.6                    |       | 13              |       |
| Wholesale                               | ** ** | **722.1**                                                                                                     | ** **    | **25**          |       | 547.7                    |       | 24              |       | 240.4                    |       | 12              |       |
| Other                                   | ** ** | **74.8**                                                                                                      | ** **    | **3**           |       | 58.0                     |       | 3               |       | 73.6                     |       | 3               |       |
| Total                                   | ** ** | **$ 2,909.9**                                                                                            | ** **    | **100**         | **%**      | $ 2,320.6           |       | 100             | %          | $ 2,070.2           |       | 100             | %          |

 

*Certain prior-year amounts have beenreclassified to conform with the current year’s presentation.*

*Mid-Atlantic Region*
| ** **                          | ** ** | **2006**                 | ** **  | **2005** | ** ** | **2004** | ** ** |
|-------------------------------------|------------|--------------------------|-------------|----------|------------|----------|------------|
| ** **                          | ** ** | ***(In millions)*** | ** **  |
| Revenues                            | ** ** | **$**                    | **2,813.5** |     | $          | 2,283.9  |       | $ | 1,925.6 |   |
| Fuel and purchased energy  expenses | ** ** | **(1,727.6**             | **)**       | (1,436.5 | )          | (946.9   | )          |
| Gross margin                        | ** ** | **$**                    | **1,085.9** |     | $          | 847.4    |       | $ | 978.7 |   |

 

The increase of$238.5 million in gross margin in 2006 compared to 2005 is primarily due toapproximately $340 million in higher gross margin mostly from favorableportfolio management, including higher margins on existing contracts and newcontracts that began in 2006.

Our wholesalemarketing, risk management, and trading operation was awarded contracts in 2006to supply a substantial portion of BGE’s standard offer service obligation toresidential customers beginning July 1, 2006 through May 31, 2007.The increase in gross margin included higher revenues from BGE of approximately$256 million mostly from these new contracts during 2006 compared to 2005. Thisincrease in gross margin was partially offset by the negative impact of higherexpenses from serving the original BGE standard offer service obligation duringthe first six months of 2006 as variable costs, including emissions and coal,continued to increase. We discuss the expiration of the BGE residential ratefreeze in more detail in the *Item 1.—Business—ElectricDeregulation and Competition* section. Our wholesale marketing, riskmanagement, and trading operation served fixed-price standard offer serviceobligations to BGE residential customers during the period from July 1,2000 until July 1, 2006.

These increases in gross margin were partially offset by:

 ̈  lowerCTC revenues of approximately $64 million due to customers that completedtheir obligation and the continued decline in the CTC rate, and

 ̈  lowergeneration at Calvert Cliffs, which resulted in lower gross margin ofapproximately $37 million, mostly because of a longer planned 2006refueling outage that included replacement of the reactor vessel head.

The decrease in Mid-Atlantic Region gross margin in 2005 compared to2004 is primarily due to rising commodity prices and hotter than normal weatherduring the third quarter of 2005, which resulted in higher load-serving costs.In addition, CTC revenues were $33.1 million lower during 2005 compared to2004. These decreases in gross margin were partially offset by the absence ofcoal delivery issues that we experienced in 2004 that had a negative impact inthat period.

*Plants with Power Purchase Agreements*
| ** **                          | ** ** | **2006**                 | ** ** | **2005** | ** ** | **2004** | ** ** |
|-------------------------------------|------------|--------------------------|------------|----------|------------|----------|------------|
| ** **                          | ** ** | ***(In millions)*** | ** ** |
| Revenues                            | ** ** | **$**                    | **650.5**  |     | $          | 665.9    |       | $ | 555.3 |   |
| Fuel and purchased energy  expenses | ** ** | **(67.9**                | )          | (72.5    | )          | (46.4    | )          |
| Gross margin                        | ** ** | **$**                    | **582.6**  |     | $          | 593.4    |       | $ | 508.9 |   |

 

*Gross margin from our Plants with PowerPurchase Agreements decreased slightly in 2006 compared to the same periods of2005. This was mostly due to approximately $14 million in lower gross marginfrom the University Park facility. As discussed in the*Revenuesand Fuel and Purchased Energy Expenses section,the University Park power purchase agreement expired in May 2006. As aresult, beginning in June 2006 until its sale in December 2006, theresults of University Park are included in the Mid-Atlantic Region.

The increase in gross margin from our Plants with Power PurchaseAgreements in 2005 compared to 2004 was primarily due to:

 ̈  highergross margin of $71.5 million from Ginna, which was acquired inJune 2004. This increase in gross margin at Ginna includes an increase inrevenues of $76.9 million*,*and

 ̈  highergross margin of $39.0 million at our Nine Mile Point facility thatbenefited from higher generation primarily due to fewer refueling outage days,the absence of an unplanned outage that occurred in January 2004, andhigher prices on the portion of our output sold into the wholesale market.

*These increases in gross margin werepartially offset by $26.0 million primarily related to changes incommodity prices that had a negative impact on realized hedging activitiesrelated to the portion of these facilities sold into the wholesale market.*

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*CompetitiveSupply*

We analyze our retail accrual, wholesale accrual, and mark-to-marketcompetitive supply activities below.

*Retail*
| ** **                          | ** ** | **2006**                 | ** **  | **2005** | ** ** | **2004** | ** ** |
|-------------------------------------|------------|--------------------------|-------------|----------|------------|----------|------------|
| ** **                          | ** ** | ***(In millions)*** | ** **  |
| Accrual revenues                    | ** ** | **$**                    | **8,000.6** |     | $          | 6,944.2  |       | $ | 4,281.0 |   |
| Fuel and purchased energy  expenses | ** ** | **(7,577.0**             | **)**       | (6,688.4 | )          | (4,011.4 | )          |
| Retail accrual activities           | ** ** | **423.6**                |        | 255.8    |       | 269.6    |       |
| Mark-to-market  activities          | ** ** | **20.9**                 |        | 18.3     |       | (1.0     | )          |
| Gross margin                        | ** ** | **$**                    | **444.5**   |     | $          | 274.1    |       | $ | 268.6 |   |

 

The increase in accrual gross margin of $167.8 million from our retailactivities during 2006 compared to 2005 is primarily due to:

 ̈  approximately $158 million in highermargins primarily due to higher electric rates and lower costs related to ourfixed-price load-serving obligations as a result of milder weather in 2006compared to the prior year, and

 ̈  approximately $13 million in higher grossmargin due to higher volumes, including 3.6 million more megawatthours of electricity and 55 billion cubic feet more of natural gas servedto retail customers during the year ended December 31, 2006 compared to2005.

The decrease in gross margin from our retail competitive supply accrualactivities in 2005 compared to 2004 is primarily due to:

 ̈  acombination of higher market prices for electricity, price volatility, and increasedcustomer usage primarily in Texas resulting mostly from extreme summer weather,which increased our cost to serve our fixed-price load-serving obligations,

 ̈  theexpiration of higher margin contracts, and

 ̈  theabsence of favorable bankruptcy settlements, which had a positive impact in2004.

These decreases were partially offset by serving approximately 20million more megawatt hours in 2005 compared to 2004 mostly due to the growthof this operation.

*Wholesale*
| ** **                          | ** ** | **2006**                 | ** **  | **2005** | ** ** | **2004** | ** ** |
|-------------------------------------|------------|--------------------------|-------------|----------|------------|----------|------------|
| ** **                          | ** ** | ***(In millions)*** | ** **  |
| Accrual revenues                    | ** ** | **$**                    | **5,232.7** |     | $          | 4,281.8  |       | $ | 3,253.7 |   |
| Fuel and purchased energy  expenses | ** ** | **(4,890.6**             | **)**       | (4,124.6 | )          | (3,113.4 | )          |
| Wholesale accrual  activities       | ** ** | **342.1**                |        | 157.2    |       | 140.3    |       |
| Mark-to-market  activities          | ** ** | **380.0**                |        | 390.5    |       | 100.1    |       |
| Gross margin                        | ** ** | **$**                    | **722.1**   |     | $          | 547.7    |       | $ | 240.4 |   |

 

Our wholesale marketing, risk management, and trading operation had$184.9 million of higher gross margin from accrual activities during 2006compared to 2005 due to:

 ̈  anincrease of approximately $145 million primarily due to new contracts enteredinto during 2006 and higher realized gross margin on existing contracts, and

 ̈an increase of approximately $85 million primarily related to the growthin our coal and natural gas activities.

These increases in gross margin were partially offset by the following:

 ̈adecrease of $24.8 million as a result of the initial public offering of CEP andthe sale of our gas-fired plants. As a result of these transactions, forecastedtransactions associated with cash-flow hedges were determined to be probable ofnot occurring, and the associated amounts previously recorded in “Accumulatedother comprehensive loss” were reclassified into earnings, and

 ̈adecrease of approximately $20 million from contract restructurings related tounit contingent power purchase agreements during the year ended December 2006compared to 2005. The termination and sale of these contracts has allowed us toeliminate our exposure to performance risk under these contracts.

Our wholesale marketing, risk management, and trading operation’saccrual gross margin was $16.9 million higher in 2005 compared to 2004primarily due to newly originated and realized business in power, gas, and coalin 2005, including several contract terminations and restructurings. During2005, we terminated or restructured several in-the-money contracts in exchangefor upfront cash payments and a reduction or cancellation of future performanceobligations. The termination or restructuring of two contracts allowed us tolower our exposure to performance risk under these contracts, and resulted inthe realization of $77.0 million of pre-tax earnings in 2005 that wouldhave been recognized over the life of these contracts. These increases werepartially offset by lower gross margins of approximately $60 millionmostly due to the absence of several favorable items, including settlements,power prices, and contracts that had a positive impact in 2004.

*Mark-to-Market*

Mark-to-market results includenet gains and losses from origination, trading, and risk management activitiesfor which we use the mark-to-market method of accounting. We discuss theseactivities and the mark-to-market method of accounting in more detail in the *Critical Accounting Policies* section andin *Note 1*.

As a result of the nature of our operations and the use ofmark-to-market accounting for certain activities, mark-to-market earnings willfluctuate. We cannot predict these fluctuations, but the impact on our earningscould be material. We discuss our market risk in more detail in the *Market Risk* section. The primary factorsthat cause fluctuations in our mark-to-market results are:

 ̈  thenumber, size, and profitability of new transactions including terminations orrestructuring of existing contracts,

 ̈  thenumber and size of our open derivative positions, and

 ̈  changesin the level and volatility of forward commodity prices and interest rates.

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Mark-to-market results were as follows:
| ** **                                             | ** ** | **2006**                 | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|--------------------------------------------------------|------------|--------------------------|------------|------------|------------|------------|------------|
| ** **                                             | ** ** | ***(In millions)*** | ** ** |
| **Unrealized mark-to-market  results**                 | ** ** | ** **               | ** ** | ** ** | ** ** | ** ** | ** ** |
| Origination gains                                      | ** ** | **$**                    | **13.5**   |       | $          | 61.6       |       | $ | 19.7 |   |
| Risk management and  trading—mark-to-market       |       |                     |       |       |       |       |       |
| Unrealized changes in  fair value                      | ** ** | **387.4**                |       | 347.2      |       | 79.4       |       |
| Changes in valuation  techniques                       |       | —                   |       | —     |       | —     |       |
| Reclassification of  settled contracts to realized     | ** ** | **(372.1**               | **)**      | (257.7     | )          | (85.4      | )          |
| Total risk management and  trading—mark-to-market | ** ** | **15.3**                 |       | 89.5       |       | (6.0       | )          |
| Total unrealized mark-to-market*                       | ** ** | **28.8**                 |       | 151.1      |       | 13.7       |       |
| **Realized mark-to-market**                            | ** ** | **372.1**                |       | 257.7      |       | 85.4       |       |
| Total mark-to-market results                           | ** ** | **$**                    | **400.9**  |       | $          | 408.8      |       | $ | 99.1 |   |

** Totalunrealized mark-to-market is the sum of origination transactions and total riskmanagement and trading—mark-to-market.*

Originationgains arise primarily from contracts that our wholesale marketing, risk management,and trading operation structures to meet the risk management needs of ourcustomers or relate to our trading activities. Transactions that result inorigination gains may be unique and provide the potential for individuallysignificant gains from a single transaction.

Origination gains represent the initial fair value recognized on thesestructured transactions. The recognition of origination gains is dependent onthe existence of observable market data that validates the initial fair valueof the contract. Origination gains arose primarily from:

 ̈  3transactions completed in 2006, of which no transaction contributed in excessof $10 million pre-tax,

 ̈  6transactions completed in 2005, one of which contributed approximately$35 million pre-tax, and

 ̈  7transactions completed in 2004, of which no transaction contributed in excessof $10 million pre-tax.

As noted above, the recognition of origination gains is dependent onsufficient observable market data that validates the initial fair value of thecontract. Liquidity and market conditions impact our ability to identifysufficient, objective market-price information to permit recognition oforigination gains. As a result, while our strategy and competitive positionprovide the opportunity to continue to originate such transactions, the levelof origination gains we are able to recognize may vary from year to year as aresult of the number, size, and market-price transparency of theindividual transactions executed in any period.

Risk management and trading—mark-to-market represents both realized andunrealized gains and losses from changes in the value of our portfolio,including the recognition of gains associated with decreases in the close-outadjustment when we are able to obtain sufficient market price information. Inaddition, we use derivative contracts subject to mark-to-market accounting tomanage our exposure to changes in market prices primarily as a result of ourgas transportation and storage activities, while in general the underlyingphysical transactions related to our gas activities are accounted for on anaccrual basis. We discuss the changes in mark-to-market results below. We showthe relationship between our mark-to-market results and the change in our netmark-to-market energy asset on the next page.

Totalmark-to-market results decreased $7.9 million in 2006 compared to 2005because of a decrease in origination gains of $48.1 million, mostly offset byan increase in unrealized changes in fair value of $40.2 million. Unrealizedchanges in fair value increased primarily due to higher pre-tax gains ofapproximately $105 million related to the positive impact of certain economichedges primarily related to gas transportation and storage contracts that donot qualify for or are not designated as cash-flow hedges. These mark-to-market results will be offset as werealize the related accrual load-serving positions in cash.

This increase in unrealized changes in fair value was partially offsetby:

 ̈  alower level of gains from risk management and trading—mark-to-market activitiesof approximately $45 million, and

 ̈  theabsence of a $19.5 million favorable impact related to changes in theclose-out adjustment in 2006 compared to 2005. The close-out adjustments aredetermined by the change in open positions, new transactions where we did nothave observable market price information, and existing transactions where wehave now observed sufficient market price information and/or we realized cashflows since the transactions’ inception. We discuss the close-out adjustment inmore detail in the *Critical AccountingPolicies*section.

Total mark-to-market results increased $309.7 million in 2005compared to 2004 due to:

 ̈  approximately$260 million primarily related to a higher level of risk management andtrading activities. Increases in our gas and coal activities, higher commodityprice volatility, and greater market liquidity resulted in more opportunitiesto deploy risk capital and to earn additional returns in 2005 compared to 2004.These items resulted in an increased number of transactions that were enteredinto and realized during 2005 and a higher level of open positions thatresulted in increased gains in 2005 compared to 2004. During 2005, slightlymore than half of the mark-to-market results were derived frompower, approximately one-third from gas, and the remainder from othertransactions.

 ̈  $41.9 millionrelated to a higher level of origination gains as discussed above, and

 ̈  $49.9 millionrelated to the decrease in the close-out adjustment during 2005 compared to theprior year for transactions that we have now observed sufficient market priceinformation and/or we realized cash flows since the transactions’ inception.

These increases in mark-to-market results were partially offset by theimpact of $41.5 million of higher mark-to-market losses on certaineconomic hedges that did not qualify for cash-flow hedge accounting treatment.Changing forward prices result inshifting value between accrual contracts and the associated mark-to-marketpositions of certain contracts in New England that contain fuel adjustmentclauses and gas transportation contract hedges, producing a timing differencein the recognition of earnings on these transactions. These 

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mark-to-market hedges are economicallyeffective; however, they do not qualify for cash-flow hedge accounting underSFAS No. 133. As a result, we recorded $41.2 million of pre-taxlosses in 2005 and $0.3 million of pre-tax gains in 2004. Thesemark-to-market gains and losses will be offset as we realize the relatedaccrual load-serving positions in cash.

*Mark-to-MarketEnergy Assets and Liabilities*

Ourmark-to-market energy assets and liabilities are comprised of derivativecontracts. While some of our mark-to-market contracts represent commodities orinstruments for which prices are available from external sources, othercommodities and certain contracts are not actively traded and are valued usingother pricing sources and modeling techniques to determine expected futuremarket prices, contract quantities, or both. We discuss our modeling techniqueslater in this section.

Mark-to-market energy assets and liabilitiesconsisted of the following:
| ***At December 31,*** | ** ** | **2006**                 | ** **  | **2005** | ** ** |
|---------------------------------|------------|--------------------------|-------------|----------|------------|
| ** **                      | ** ** | ***(In millions)*** | ** **  |
| Current Assets                  | ** ** | **$**                    | **1,294.8** |     | $          | 1,339.2 |   |
| Noncurrent Assets               | ** ** | **623.4**                |        | 1,089.3  |       |
| Total Assets                    | ** ** | **1,918.2**              |        | 2,428.5  |       |
| Current Liabilities             | ** ** | **1,071.7**              |        | 1,348.7  |       |
| Noncurrent Liabilities          | ** ** | **392.4**                |        | 912.3    |       |
| Total Liabilities               | ** ** | **1,464.1**              |        | 2,261.0  |       |
| Net mark-to-market energy asset | ** ** | **$**                    | **454.1**   |     | $          | 167.5 |   |

 

The following are the primary sources of thechange in net mark-to-market energy asset during 2006 and 2005:
| ** **                                               | ** ** | **2006**                 | ** ** | **2005**  | ** ** |
|----------------------------------------------------------|------------|--------------------------|------------|-----------|------------|
| ** **                                               | ** ** | ***(In millions)*** | ** ** |
| Fair value beginning of year                             | ** ** | ** **               |       | **$**     | **167.5**  |   |   |   | $ | 52.4 |   |
| Changes in fair value recorded  in earnings              |       |                     |       |      |       |   |   |   |   |
| Origination gains                                        | ** ** | **$**                    | **13.5**   |      |       |   | $ | 61.6 |   |   |   |
| Unrealized changes in  fair value                        | ** ** | **387.4**                |       |      |       | 347.2 |   |   |   |
| Changes in valuation  techniques                         |       | —                   |       |      |       | — |   |   |   |
| Reclassification of  settled contracts to realized       | ** ** | **(372.1**               | **)**      |      |       | (257.7 | ) |   |   |
| Total changes in fair value  recorded in earnings        | ** ** | ** **               |       | **28.8**  |       |   |   | 151.1 |   |
| Changes in value of exchange-listed  futures and options | ** ** | ** **               |       | **277.8** |       |   |   | (119.9 | ) |
| Net change in premiums on  options                       | ** ** | ** **               |       | **(29.8** | **)**      |   |   | 79.7 |   |
| Contracts acquired                                       |       |                     |       | —    |       |   |   | 17.4 |   |
| Other changes in fair value                              | ** ** | ** **               |       | **9.8**   |       |   |   | (13.2 | ) |
| Fair value at end of year                                | ** ** | ** **               |       | **$**     | **454.1**  |   |   |   | $ | 167.5 |   |
|                                                          |            |                          |            |           |            |  |  |  |  |  |  |  |  |

 

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

 ̈  Originationgains represent the initial unrealized fair value at the time these contractsare executed to the extent permitted by applicable accounting rules.

 ̈  Unrealizedchanges in fair value represent unrealized changes in commodity prices, thevolatility of options on commodities, the time value of options, and othervaluation adjustments.

 ̈  Changesin valuation techniques represent improvements in estimation techniques,including modeling and other statistical enhancements used to value ourportfolio to reflect more accurately the economic value of our contracts.

 ̈  Reclassificationof settled contracts to realized represents the portion of previouslyunrealized amounts settled during the period and recorded as realized revenues.

The netmark-to-market energy asset also changed due to the following items recorded inaccounts other than in our Consolidated Statements of Income:

 ̈  Changesin value of exchange-listed futures and options are adjustments to removeunrealized revenue from exchange-traded contracts that are included inrisk management revenues. The fair value of these contracts is recorded in “Accountsreceivable” rather than “Mark-to-market energy assets” in our ConsolidatedBalance Sheets because these amounts are settled through our margin accountwith a third-party broker.

 ̈  Netchanges in premiums on options reflects the accounting for premiums on optionspurchased as an increase in the net mark-to-market energy asset and premiums onoptions sold as a decrease in the net mark-to-market energy asset.

 ̈  Contractsacquired represents the initial fair value of acquired derivative contractsrecorded in “Mark-to-market energy assets.”

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The settlement terms of our net mark-to-market energy asset and sourcesof fair value as of December 31, 2006 are as follows:
| ** **                              | ** ** | **Settlement Term** | ** ** | ** ** | ** ** |
|-----------------------------------------|------------|--------------------------|------------|------------|------------|
| ** **                              | ** ** | **2007**                 | ** ** | **2008**   | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **2012** | ** ** | **Thereafter** | ** ** | **Fair Value** | ** ** |
| ** **                              | ** ** | ***(In millions)*** | ** ** | ** ** | ** ** |
| Prices provided by external sources (1) |       | $                        | 192.7      |       | $          | 205.5 |   | $ | 6.1 |   | $ | 27.0 |   | $ | 5.4 |   | $ | 8.7 |   |   | $ | 3.4 |   |   |   | $ | 448.8 |   |   |
| Prices based on models                  |       | 30.4                     |       | (0.9       | )          | (1.0 | ) | (13.6 | ) | (6.9 | ) | (5.3 | ) |   | 2.6 |   |   |   | 5.3 |   |   |
| Total net mark-to-market energy asset   |       | $                        | 223.1      |       | $          | 204.6 |   | $ | 5.1 |   | $ | 13.4 |   | $ | (1.5 | ) | $ | 3.4 |   |   | $ | 6.0 |   |   |   | $ | 454.1 |   |   |

 

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

We manage our mark-to-marketrisk on a portfolio basis based upon the delivery period of our contracts andthe individual components of the risks within each contract. Accordingly, werecord and manage the energy purchase and sale obligations under our contractsin separate components based upon the commodity (e.g., electricity or gas), theproduct (e.g., electricity for delivery during peak or off-peak hours), thedelivery location (e.g., by region), the risk profile (e.g., forward oroption), and the delivery period (e.g., by month and year).

Consistent withour risk management practices, we have presented the information in the tableabove based upon the ability to obtain reliable prices for components of therisks in our contracts from external sources rather than on acontract-by-contract basis. Thus, the portion of long-term contracts that is valuedusing external price sources is presented under the caption “prices provided byexternal sources.” This is consistent with how we manage our risk, and webelieve it provides the best indication of the basis for the valuation of ourportfolio. Since we manage our risk on a portfolio basis rather thancontract-by-contract, it is not practicable to determine separately the portionof long-term contracts that is included in each valuation category. We describethe commodities, products, and delivery periods included in each valuationcategory in detail below.

The amounts for which fair value is determined using prices provided byexternal sources represent the portion of forward, swap, and option contractsfor which price quotations are available through brokers or over-the-countertransactions. The term for which such price information is available varies bycommodity, region, and product. The fair values included in this category arethe following portions of our contracts:

 ̈  forward purchases and sales of electricity duringpeak and off-peak hours for delivery terms primarily through 2010, but up to2012, depending upon the region,

 ̈  options for the purchase and sale of electricityduring peak hours for delivery terms through 2008, depending upon the region,

 ̈  forward purchases and sales of electric capacity fordelivery terms primarily through 2007, but up to 2008, depending on the region,

 ̈  forward purchases and sales of natural gas, coal, andoil for delivery terms through 2011, and

 ̈  options for the purchase and sale of natural gas,coal, and oil for delivery terms through 2008.

The remainderof the net mark-to-market energy asset is valued using models. The portion ofcontracts for which such techniques are used includes standard products forwhich external prices are not available and customized products that are valuedusing modeling techniques to determine expected future market prices, contractquantities, or both.

Modeling techniques include estimating the present value of cash flowsbased upon underlying contractual terms and incorporate, where appropriate,option pricing models and statistical and simulation procedures. Inputs to themodels include:

 ̈  observable market prices,

 ̈  estimated market prices in the absence of quotedmarket prices,

 ̈  the risk-free market discount rate,

 ̈  volatility factors,

 ̈  estimated correlation of energy commodity prices, and

 ̈  expected generation profiles of specific regions.

Additionally,we incorporate counterparty-specific credit quality and factors formarket price and volatility uncertainty and other risks in our valuation. Theinputs and factors used to determine fair value reflect management’s bestestimates.

Theelectricity, fuel, and other energy contracts we hold have varying terms tomaturity, ranging from contracts for delivery the next hour to contracts withterms of ten years or more. Because an active, liquid electricity futuresmarket comparable to that for other commodities has not developed, the majorityof contracts used in the wholesale marketing, risk management, and tradingoperation are direct contracts between market participants and are not exchange-tradedor financially settling contracts that can be readily liquidated in theirentirety through an exchange or other market mechanism. Consequently, we andother market participants generally realize the value of these contracts ascash flows become due or payable under the terms of the contracts rather thanthrough selling or liquidating the contracts themselves.

Consistent withour risk management practices, the amounts shown in the table above as beingvalued using prices from external sources include the portion of long-termcontracts for which we can obtain reliable prices from external sources. Theremaining portions of these long-term contracts are shown in the table as beingvalued using models. In order to realize the entire value of a long-termcontract in a single transaction, we would need to sell or assign the entirecontract. If we were to sell or assign any of our long-term contracts in theirentirety, we may realize an amount different from the value reflected in thetable. However, based upon the nature of the wholesale marketing, riskmanagement, and trading operation, we generally expect to realize the value ofthese contracts, as well as any contracts we may enter into in the future tomanage our risk, over time as the contracts and related hedges settle inaccordance with their terms. In general, we do not expect to realize the valueof these contracts and related hedges by selling or assigning the contractsthemselves in total.

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The fair valuesin the table represent expected future cash flows based on the level of forwardprices and volatility factors as of December 31, 2006 and could changesignificantly as a result of future changes in these factors. Additionally,because the depth and liquidity of the power markets vary substantially betweenregions and time periods, the prices used to determine fair value could beaffected significantly by the volume of transactions executed.

Management uses its best estimates to determine the fair value ofcommodity and derivative contracts it holds and sells. These estimates considervarious factors including closing exchange and over-the-counter pricequotations, time value, volatility factors, and credit exposure. However,future market prices and actual quantities will vary from those used inrecording mark-to-market energy assets and liabilities, and it is possible thatsuch variations could be material.

***Risk ManagementAssets and Liabilities***

We record derivatives that qualify fordesignation as hedges under SFAS No. 133 in “Risk management assets andliabilities” in our Consolidated Balance Sheets. Our risk management assets andliabilities consisted of the following:
| ***At December 31,***       | ** ** | **2006**                 | ** **   | **2005** | ** ** |
|---------------------------------------|------------|--------------------------|--------------|----------|------------|
| ** **                            | ** ** | ***(In millions)*** | ** **   |
| Current Assets                        | ** ** | **$**                    | **261.7**    |     | $          | 1,244.3 |   |
| Noncurrent Assets                     | ** ** | **325.7**                |         | 626.0    |       |
| Total Assets                          | ** ** | **587.4**                |         | 1,870.3  |       |
| Current Liabilities                   | ** ** | **1,340.0**              |         | 483.5    |       |
| Noncurrent Liabilities                | ** ** | **707.3**                |         | 1,035.5  |       |
| Total Liabilities                     | ** ** | **2,047.3**              |         | 1,519.0  |       |
| Net risk management (liability) asset | ** ** | **$**                    | **(1,459.9** | **)**    | $          | 351.3 |   |

 

The decrease in our net risk management asset of $1.8 billion since December 31,2005 was due primarily to decreases in power prices that reduced the fair valueof our cash-flow hedge positions and the settlement of cash-flow hedges during2006. A decrease in the fair value of our cash-flow hedges indicates anincrease in value of the accrual positions to which these hedges are related.

*Other*
| ** ** | ** ** | **2006**                 | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------|------------|--------------------------|------------|----------|------------|----------|------------|
| ** ** | ** ** | ***(In millions)*** | ** ** |
| Revenues   | ** ** | **$**                    | **74.8**   |     | $          | 58.0     |       | $ | 73.6 |   |
|            |            |                          |            |          |            |          |            |  |  |  |

 

Our merchantenergy business holds up to a 50% voting interest in 24 operating domesticenergy projects that consist of electric generation, fuel processing, or fuelhandling facilities. Of these 24 projects, 17 are “qualifying facilities” thatreceive certain exemptions based on the facilities’ energy source or the use ofa cogeneration process. Earnings from our investments were $13.8 million in2006, $3.6 million in 2005, and $18.0 million in 2004.

Our investment in qualifying facilities and domestic power projectsconsisted of the following:
| **Book Value at December 31,** | ** ** | **2006**                 | ** ** | **2005** | ** ** |
|----------------------------------------------------|------------|--------------------------|------------|----------|------------|
| ** **                                         | ** ** | ***(In millions)*** | ** ** |
| Project Type                                       |       |                     |       |     |       |
| Coal                                               | ** ** | **$**                    | **125.7**  |     | $          | 127.8 |   |
| Hydroelectric                                      | ** ** | **55.1**                 |       | 55.9     |       |
| Geothermal                                         | ** ** | **40.5**                 |       | 43.7     |       |
| Biomass                                            | ** ** | **46.6**                 |       | 48.0     |       |
| Fuel  Processing                                   | ** ** | **33.7**                 |       | 23.8     |       |
| Solar                                              | ** ** | **7.0**                  |       | 7.0      |       |
| Total                                              | ** ** | **$**                    | **308.6**  |     | $          | 306.2 |   |

 

We believe thecurrent market conditions for our equity-method investments that owngeothermal, coal, hydroelectric, and fuel processing projects providesufficient positive cash flows to recover our investments. We continuouslymonitor issues that potentially could impact future profitability of theseinvestments, including environmental and legislative initiatives. We discusscertain 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, ourinvestments in these projects could become impaired under the provisions of APBNo. 18.

The ability torecover our equity- and cost-method investments that own biomass andsolar projects is partially dependent upon subsidies from the State ofCalifornia. Under the California Public Utility Act, subsidies currently existin that the California Public Utilities Commission (CPUC) requires load-servingentities to identify a separate rate component to be collected from customersto fund the development of renewable resources technologies, including solar,biomass, and wind facilities. In addition, legislation in California requiresthat each load-serving entity increase its total procurement of eligiblerenewable energy resources by at least one percent per year so that 20% of itsretail sales are procured from eligible renewable energy resources by 2017. Thelegislation also requires the California Energy Commission to awardsupplemental energy payments to load-serving entities to cover above-marketcosts of renewable energy.

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

***OperatingExpenses***

Our merchant energy business operating expenses increased$203.3 million in 2006 compared to 2005 mostly due to the following:

 ̈  an increase of $139.2 million at our competitivesupply operations primarily related to higher labor and benefit costs and theimpact of inflation on other costs,

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 ̈  an increase of $22.7 million at our upstream gasoperations, primarily due to acquisitions made in June 2005, and

 ̈  an increase of approximately $18 million at ourgenerating facilities, which includes higher expenses associated with longerplanned outages, offset in part by lower expenses that resulted from ourproductivity initiatives.

Our merchant energy business operating expenses increased$196.2 million in 2005 compared to 2004 mostly due to the following:

 ̈  an increase of $101.8 million at our wholesalemarketing, risk management, and trading operation due to an increase incompensation and benefit costs including our expanding gas and coal operations,

 ̈  an increase of $81.5 million from Ginna, whichwas acquired in June 2004,

 ̈  an increase of $26.5 million at our retailoperation primarily related to a $10.8 million increase in uncollectibleexpenses and a $8.7 million increase in aggregator fees,

 ̈  an increase of $17.3 million at our gas-firedgenerating facilities primarily due to increased corporate overhead expenses,and

 ̈  an increase of $13.0 million at Calvert Cliffsprimarily due to an increase in corporate overhead expenses, partially offsetby fewer employees and a shorter refueling outage in 2005.

These increases in expense were partially offset by lower operatingexpenses of $56.5 million at Nine Mile Point primarily due to lowerrefueling outage expenses and a lower number of employees and contractors.

***WorkforceReduction Costs***

Our merchant energy business recognized expenses associated with ourworkforce reduction efforts as discussed in more detail in *Note 2*.

***Merger-RelatedCosts***

We discuss costs related to the merger with FPL Group, which has beenterminated, in *Note 15*.

***Depreciation,Depletion, and Amortization Expense***

Merchant energy depreciation, depletion, and amortization expensesincreased $28.5 million in 2005 compared to 2004 mostly due to:

 ̈  $10.2 million related to our South Carolinasynthetic fuel facility,

 ̈  $8.8 million related to Ginna, which wasacquired in June 2004, and

 ̈  $6.0 million increaserelated to our 2005 investments in gas producing facilities.

***Accretion ofAsset Retirement Obligations***

The increase inaccretion expense of $8.9 million in 2005 compared to 2004 is primarilydue to Ginna which was acquired in June 2004 and the impact of normalcompounding.

***Taxes OtherThan Income Taxes***

Merchant energytaxes other than income taxes increased $13.3 million in 2006 compared to2005 mostly due to $5.3 million related to higher gross receipts taxes atour retail competitive supply operation and $3.1 million related to ourworking interests in gas producing properties.

Merchant energy taxes other than income taxes increased$23.4 million in 2005 compared to 2004 mostly due to $19.6 millionrelated to higher gross receipts taxes at our retail electric operation and$4.0 million related to property taxes for Ginna.

**Regulated ElectricBusiness**

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

***Results***
| ** **                                       | ** ** | **2006**                 | ** **  | **2005** | ** ** | **2004** | ** ** |   |
|--------------------------------------------------|------------|--------------------------|-------------|----------|------------|----------|------------|--------|
| ** **                                       | ** ** | ***(In millions)*** | ** **  |     |
| Revenues                                         | ** ** | **$**                    | **2,115.9** |     | $          | 2,036.5  |       | $      | 1,967.7 |   |   |
| Electricity purchased for resale expenses        | ** ** | **(1,167.8**             | **)**       | (1,068.9 | )          | (1,034.0 | )          |   |
| Operations and maintenance expenses              | ** ** | **(351.3**               | **)**       | (318.4   | )          | (304.2   | )          |   |
| Merger-related costs                             | ** ** | **(3.3**                 | **)**       | (4.0     | )          | —   |       |   |
| Depreciation and amortization                    | ** ** | **(181.5**               | **)**       | (185.8   | )          | (194.2   | )          |   |
| Taxes other than income taxes                    | ** ** | **(134.9**               | **)**       | (135.3   | )          | (132.8   | )          |   |
| Income from Operations                           | ** ** | **$**                    | **277.1**   |     | $          | 324.1    |       | $      | 302.5 |   |   |
| Net Income                                       | ** ** | **$**                    | **120.2**   |     | $          | 149.4    |       | $      | 131.1 |   |   |
| *Other Items Included in Operations (after-tax)* | ** ** |
| Merger-related costs                             | ** ** | **$**                    | **(0.8**    | **)**    | $          | (3.7     | )          | $      | — | ** ** |   |

 

*Aboveamounts include intercompany transactions eliminated in our*

*Consolidated Financial Statements.Note 3 provides a reconciliation of operating results by segment to ourConsolidated Financial Statements.*

Net income from the regulated electric business decreased$29.2 million in 2006 compared to 2005 mostly because of the following:

 ̈  increased operations andmaintenance expenses of $19.9 million after-tax mostly due to higher labor andbenefit costs and incremental costs associated with 2006 storms, and

 ̈  decreased revenues lesselectricity purchased for resale expenses of $11.8 million after-tax.

Net income from the regulated electric business increased$18.3 million in 2005 compared to 2004 mostly because of the following:

 ̈  increased revenues lesselectricity purchased for resale expenses of $20.7 million after-tax,

 ̈  decreased depreciation andamortization expense of $5.1 million after-tax, and

 ̈  increased other income primarilydue to gains on the sales of land of $3.6 million after-tax.

48

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These favorable results werepartially offset by the following:

 ̈  increased operations and maintenance expenses of$8.7 million after-tax mostly due to higher labor and benefit costs andthe impact of inflation on other costs, and

 ̈  merger-related transactioncosts of $3.7 million after-tax.

***ElectricRevenues***

The changes in electric revenues in 2006 and 2005 compared to therespective prior year were caused by:
| ** **                                                   | ** ** | **2006**                 | ** ** | **2005** | ** ** |
|--------------------------------------------------------------|------------|--------------------------|------------|----------|------------|
| ** **                                                   | ** ** | ***(In millions)*** | ** ** |
| Distribution volumes                                         | ** ** | **$**                    | **(40.9**  | **)**    | $          | 21.3 |   |
| Standard offer service                                       | ** ** | **433.7**                |       | 38.8     |       |
| Rate stabilization credits                                   | ** ** | **(321.9**               | **)**      | —   |       |
| Total change in electric revenues from electric system sales | ** ** | **70.9**                 |       | 60.1     |       |
| Other                                                        | ** ** | **8.5**                  |       | 8.7      |       |
| Total change in electric revenues                            | ** ** | **$**                    | **79.4**   |     | $          | 68.8 |   |

 

*Distribution Volumes*

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

The percentage changes in our electric system distribution volumes, bytype of customer, in 2006 and 2005 compared to the respective prior year were:
| ** **  | ** ** | **2006** | ** ** | **2005** | ** ** |
|-------------|------------|----------|------------|----------|------------|
| Residential | ** ** |     | **(6.4**   | **)%**   |       |   | 3.4 | % |   |
| Commercial  | ** ** |     | **(0.6**   | **)**    |       |   | 5.1 |   |   |
| Industrial  | ** ** |     | **(7.5**   | **)**    |       |   | (6.4 | ) |   |

 

In 2006, we distributed lesselectricity to residential customers mostly due to milder weather and decreasedusage per customer, partially offset by an increased number of customers. Wedistributed less electricity to commercial customers mostly due to milderweather, partially offset by an increased number of customers and increasedusage per customer. We distributed less electricity to industrial customersmostly due to decreased usage per customer.

In 2005, we distributed more electricity to residential customerscompared to 2004 mostly due to warmer summer weather and an increased number ofcustomers. We distributed more electricity to commercial customers mostly dueto increased usage per customer, an increased number of customers, and warmer summerweather. We distributed less electricity to industrial customers mostly due todecreased usage per customer.

*StandardOffer Service*

BGE providesstandard offer service for customers that do not select an alternativesupplier. We discuss the provisions of Maryland’s Senate Bill 1 related toresidential electric rates in the *Item 1.Business—Electric Regulatory Matters and Competition* section.

Standard offerservice revenues were higher in 2006 compared to 2005 mostly due to an increaseto market prices in the standard offer service rates due to the expiration ofthe residential rate freeze in July 2006, partially offset by lowerstandard offer service volumes.

Standard offer service revenues increased in 2005 compared to 2004mostly because of increased standard offer service volumes to residentialcustomers and increased standard offer service rates for all customerspartially offset by lower standard offer service volumes associated with thosecommercial and industrial customers that elected alternative suppliersbeginning July 1, 2004.

*Rate Stabilization Credits*

As a result of Senate Bill 1, we are required to defer a portion of thefull market rate increase during the eleven month period from July 1, 2006until May 31, 2007 for recovery in the future. Therefore, the increase instandard offer service revenues is partially offset by rate stabilizationcredits in order to reduce rates for residential customers from market price tothe approved increase of 15% in Senate Bill 1.

***ElectricityPurchased for Resale Expenses***

Electricity purchased for resale expensesinclude the cost of electricity purchased for resale to our standard offerservice customers. These costs do not include the cost of electricity purchasedby delivery service only customers. The following table summarizes ourregulated electricity purchased for resale expenses:
| ** **                                | ** ** | **2006**                 | ** **  | **2005** | ** ** | **2004** | ** ** |
|-------------------------------------------|------------|--------------------------|-------------|----------|------------|----------|------------|
| ** **                                | ** ** | ***(In millions***) | ** **  |
| Actual costs                              | ** ** | **$**                    | **1,489.7** |     | $          | 1,068.9  |       | $ | 1,034.0 |   |
| Deferral under rate stabilization plan    | ** ** | **(321.9**               | **)**       | —   |       | —   |       |
| Electricity purchased for resale expenses | ** ** | **$**                    | **1,167.8** |     | $          | 1,068.9  |       | $ | 1,034.0 |   |

 

*Actual Costs*

BGE’s actual costsfor electricity purchased for resale increased $420.8 million in 2006 comparedto 2005 due to higher  contractprices to purchase electricity resulting from the expiration of contracts thatwere executed in 2000 as part of the implementation of electric deregulation inMaryland, partially offset by lower standard offer service volumes. 

BGE’s actual costs for electricity purchased for resale increased$34.9 million in 2005 compared to 2004 mostly because of increasedstandard offer service volumes to residential customers and higher costs toserve all standard offer service customers, partially offset by lowerelectricity purchased for resale expenses associated with commercial andindustrial customers that elected alternative suppliers beginning July 1,2004.

*Deferral under RateStabilization Plan*

We defer the difference between our actual costs of electricitypurchased for resale and what we are allowed to bill customers under SenateBill 1. In 2006, we deferred $321.9 million in electricity purchased for resaleexpenses. These deferred expenses, plus carrying charges, are included in “RegulatoryAssets (net)” in our, and BGE’s, Consolidated Balance Sheets. We discuss theprovisions of Senate Bill 1 related to residential 

49

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electric rates in the *Item 1. Business—Electric Regulatory Matters and Competition* section.

***ElectricOperations and Maintenance Expenses***

Regulatedelectric operations and maintenance expenses increased $32.9 million in2006 compared to 2005 mostly due to higher labor and benefit costs and theimpact of inflation on other costs and $13.1 million of incrementaldistribution service restoration expenses associated with 2006 storms.

Regulated electric operations and maintenance expenses increased$14.2 million in 2005 compared to 2004 mostly due to higher labor andbenefit costs and the impact of inflation on other costs.

***Merger-RelatedTransaction Costs***

We discuss costs related to the merger with FPL Group, which has beenterminated, in *Note 15*.

***ElectricDepreciation and Amortization Expense***

Regulated electricdepreciation and amortization expense decreased $4.3 million in 2006 comparedto 2005 mostly because of the absence of $6.9 million amortization expenseassociated with certain software, partially offset by $3.0 million related toadditional property placed in service.

Regulated electric depreciation and amortization expense decreased$8.4 million in 2005 compared to 2004 mostly because of the absence of$12.6 million of accelerated amortization expense associated with certaininformation technology assets replaced in 2004, partially offset by$4.2 million related to additional property placed in service.

**Regulated Gas Business**

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

***Results***
| ** **                                       | ** ** | **2006**                 | ** ** | **2005** | ** ** | **2004** | ** ** |
|--------------------------------------------------|------------|--------------------------|------------|----------|------------|----------|------------|
| ** **                                       | ** ** | ***(In millions)*** | ** ** |
| Revenues                                         | ** ** | **$**                    | **899.5**  |     | $          | 972.8    |       | $ | 757.0 |   |
| Gas purchased for resale expenses                | ** ** | **(581.5**               | **)**      | (687.5   | )          | (484.3   | )          |
| Operations and maintenance expenses              | ** ** | **(144.8**               | **)**      | (131.8   | )          | (123.6   | )          |
| Merger-related costs                             | ** ** | **(1.4**                 | **)**      | (1.4     | )          | —   |       |
| Depreciation and amortization                    | ** ** | **(46.0**                | **)**      | (46.6    | )          | (48.1    | )          |
| Taxes other than income taxes                    | ** ** | **(33.8**                | **)**      | (33.1    | )          | (32.1    | )          |
| Income from Operations                           | ** ** | **$**                    | **92.0**   |     | $          | 72.4     |       | $ | 68.9 |   |
| Net Income                                       | ** ** | **$**                    | **37.0**   |     | $          | 26.7     |       | $ | 22.2 |   |
| *Other Items Included in Operations (after-tax)* |       |
| Merger-related costs                             | ** ** | **$**                    | **(0.4**   | **)**    | $          | (1.3     | )          | $ | — |   |

 

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

Net income from the regulatedgas business increased $10.3 million in 2006 compared to 2005 mostly dueto increased revenues less gas purchased for resale expenses of$19.8 million after-tax, which was primarily due to the increase in gasbase rates that was approved by the Maryland PSC in December 2005. Thisincrease was partially offset by higher operations and maintenance expenses of$7.9 million after-tax.

Net income from our regulated gas business was about the same in 2005compared to 2004.

***Gas Revenues***

The changes ingas revenues in 2006 and 2005 compared to the respective prior year were causedby:
| ** **                                         | ** ** | **2006**                 | ** ** | **2005** | ** ** |
|----------------------------------------------------|------------|--------------------------|------------|----------|------------|
| ** **                                         | ** ** | ***(In millions)*** | ** ** |
| Distribution volumes                               | ** ** | **$**                    | **(38.0**  | **)**    | $          | 3.9 |   |
| Base rates                                         | ** ** | **33.4**                 |       | 2.6      |       |
| Revenue decoupling                                 | ** ** | **28.4**                 |       | 2.5      |       |
| Gas cost adjustments                               | ** ** | **(112.3**               | **)**      | 129.1    |       |
| Total change in gas revenues from gas system sales | ** ** | **(88.5**                | **)**      | 138.1    |       |
| Off-system sales                                   | ** ** | **13.9**                 |       | 77.5     |       |
| Other                                              | ** ** | **1.3**                  |       | 0.2      |       |
| Total change in gas revenues                       | ** ** | **$**                    | **(73.3**  | **)**    | $          | 215.8 |   |

 

*DistributionVolumes*

The percentage changes in our distributionvolumes, by type of customer, in 2006 and 2005 compared to the respective prioryear were:
| ** **  | ** ** | **2006**  | ** ** | **2005** | ** ** |
|-------------|------------|-----------|------------|----------|------------|
| Residential |       | **(17.0** | **)%**     | (1.3     | )%         |
| Commercial  |       | **(13.3** | **)**      | (9.0     | )          |
| Industrial  |       | **3.2**   | ** ** | 33.6     |       |

 

 

In 2006, wedistributed less gas to residential and commercial customers compared to 2005mostly due to milder weather and decreased usage per customer, partially offsetby an increased number of customers. We distributed more gas to industrialcustomers mostly due to increased usage per customer.

In 2005, we distributed less gas to residential and commercialcustomers compared to 2004 mostly due to decreased usage per customer partiallyoffset by colder winter weather and an increased number of customers. We distributedmore gas to industrial customers mostly due to increased usage per customer.

*Base Rates*

In December 2005, the Maryland PSC issued an order granting BGE a$35.6 million annual increase in its gas base rates. In December 2006, theBaltimore City Circuit Court upheld the rate order. However, certain partieshave filed an appeal with the Court of Special Appeals. We cannot provideassurance that the Maryland PSC’s order will not be reversed in whole or inpart or that certain issues will not be remanded to the Maryland PSC forreconsideration.

50

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*RevenueDecoupling*

The Maryland PSC allows us to record a monthly adjustment to our gasdistribution revenues to eliminate the effect of abnormal weather patterns onour gas distribution volumes. This means our monthly gas distribution revenuesare based on weather that is considered “normal” for the month and, therefore,are not affected by actual weather conditions.

*Gas CostAdjustments*

We charge ourgas customers for the natural gas they purchase from us using gas costadjustment clauses set by the Maryland PSC as described in *Note 1*. However, under the market-basedrates mechanism approved by the Maryland PSC, our actual cost of gas iscompared to a market index (a measure of the market price of gas in a givenperiod). The difference between our actual cost and the market index is sharedequally between shareholders and customers.

Customers whodo not purchase gas from BGE are not subject to the gas cost adjustment clausesbecause we are not selling gas to them. However, these customers are chargedbase rates to recover the costs BGE incurs to deliver their gas through ourdistribution system, and are included in the gas distribution volume revenues.

Gas costadjustment revenues decreased in 2006 compared to 2005 because we sold less gasat lower prices.

Gas cost adjustment revenues increased in 2005 compared to 2004 becausewe sold more gas at higher prices.

*Off-SystemSales*

Off-system gassales 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 anarrangement for part of the margin from off-system sales to benefit customers(through reduced costs) and the remainder to be retained by BGE (which benefitsshareholders). Changes in off-system sales do not significantly impactearnings.

Revenues fromoff-system gas sales increased in 2006 compared to 2005 because we sold moregas, partially offset by lower prices.

Revenues from off-system gas sales increased in 2005 compared to 2004because we sold more gas at higher prices.

***Gas PurchasedFor Resale Expenses***

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

Gas purchasedfor resale expenses decreased $106.0 million in 2006 compared to 2005because we purchased less gas at lower prices.

Gas purchased for resale expenses increased in 2005 compared to 2004because we purchased more gas at higher prices.

***Gas Operationsand Maintenance Expenses***

Regulatedgas operations and maintenance expenses increased $13.0 million in 2006compared to 2005 mostly due to higher labor and benefit costs and the impact ofinflation on other costs.

Regulated gas operations and maintenance expenses increased$8.2 million in 2005 compared to 2004 mostly due to higher compensationand benefit costs and the impact of inflation on other costs.

***Merger-RelatedTransaction Costs***

We discuss costs related to the merger with FPL Group, which has beenterminated, in *Note 15*.

**Other Nonregulated Businesses**

*Results*
| ** **                                                                                                              | ** ** | **2006**                 | ** ** | **2005** | ** ** | **2004** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------|------------|--------------------------|------------|----------|------------|----------|------------|
| ** **                                                                                                              | ** ** | ***(In millions)*** | ** ** |
| Revenues                                                                                                                | ** ** | **$**                    | **231.0**  |     | $          | 207.0    |       | $ | 201.1 |   |
| Operating expenses                                                                                                      | ** ** | **(173.1**               | **)**      | (156.2   | )          | (180.0   | )          |
| Merger-related costs                                                                                                    | ** ** | **(0.5**                 | **)**      | (0.4     | )          | —   |       |
| Depreciation and amortization                                                                                           | ** ** | **(37.7**                | **)**      | (40.2    | )          | (24.2    | )          |
| Taxes other than income taxes                                                                                           | ** ** | **(2.0**                 | **)**      | (2.0     | )          | (2.4     | )          |
| Income (Loss) from Operations                                                                                           | ** ** | **$**                    | **17.7**   |     | $          | 8.2      |       | $ | (5.5 | ) |
| Income (Loss) from continuing operations and before cumulative  effects of changes in accounting principles (after-tax) | ** ** | **$**                    | **11.3**   |     | $          | 0.4      |       | $ | (12.9 | ) |
| Income from  discontinued operations (after-tax)                                                                   | ** ** | **0.9**                  |       | 20.6     |       | 9.4      |       |
| Cumulative  effects of changes in accounting  principles (after-tax)                                                    | ** ** | **—**               |       | 0.2      |       | —   |       |
| Net Income (Loss)                                                                                                       | ** ** | **$**                    | **12.2**   |     | $          | 21.2     |       | $ | (3.5 | ) |
| *Other Items Included In  Operations (after-tax)*                                                                       |       |                     |       |
| Merger-related costs                                                                                                    | ** ** | **$**                    | **(0.2**   | **)**    | $          | (0.2     | )          | $ | — |   |

*Certain prior-year amounts have been reclassified to conform withthe current year’s presentation. Above amounts include intercompanytransactions eliminated in our Consolidated Financial Statements. Note 3provides a reconciliation of operating results by segment to our ConsolidatedFinancial Statements.*

Net income from our other nonregulated businesses decreased $9.0 millionin 2006 compared to 2005 primarily due to a $19.7 million decrease in incomefrom discontinued operations, partially offset by a $10.7 million increase innet income from our remaining other nonregulated businesses, including anincrease in net income from our continued liquidation of our real estateinvestments.

Net income from our other nonregulated businesses increased$24.7 million in 2005 compared to 2004 primarily due to:

 ̈  a$16.1 million after-tax gain on sale of Constellation Power InternationalInvestments, Ltd., which held our other nonregulated internationalinvestments, in October 2005, and

 ̈  a$13.2 million after-tax increase in net income from the continuedliquidation of our financial investments.

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These increases were partiallyoffset by $4.9 million lower net income from our other nonregulatedinternational investments due to their sale in October 2005. We discussthe sale of our other nonregulated international investments in more detail in *Note 2*.

In 2001, we decided to sell certain non-core assets and accelerate theexit strategies on other assets that we continued to hold and own. While ourintent is to dispose of these remaining non-core assets, market conditions andother events beyond our control may affect the actual sale of these assets. Inaddition, a future decline in the fair value of these assets could result inlosses that could have a material impact on our financial results.

**Consolidated Nonoperating Income and Expenses**

***Gain on InitialPublic Offering of CEP LLC***

In November 2006, CEP, a limited liability company formed byConstellation Energy, completed an initial public offering of 5.2 millioncommon units at $21 per unit. As a result of the initial public offering ofCEP, we recognized a pre-tax gain of $28.7 million, or $17.9 million afterrecording deferred taxes on the gain. We discuss the initial public offering ofCEP in more detail in *Note 2*.

***Other Income***

Other incomeincreased $40.0 million in 2005 compared to 2004 primarily because ofhigher interest and investment income due to a higher cash balance and higherdecommissioning trust asset earnings and gains on the sales of land at BGE.

Total other income at BGE increased $12.3 million in 2005 comparedto 2004 primarily due to approximately $7 million of gains on the sales ofland.

***Fixed Charges***

Total fixedcharges increased $18.5 million mostly because of a higher level of debtoutstanding, including commercial paper borrowings, and higher interest ratesin 2006 compared to 2005.

Total fixedcharges decreased $16.6 million in 2005 compared to 2004 mostly because ofthe benefit of lower interest rates due to interest rate swaps entered intoduring the third quarter of 2004 and a lower level of debt outstanding. Wediscuss the interest rate swaps in more detail in *Note 13*.

Total fixed charges for BGE increased $9.1 million in 2006compared to 2005 mostly because of a higher level of debt outstanding. Totalfixed charges for BGE decreased $2.7 million in 2005 compared to 2004mostly because of a lower level of debt outstanding.

***Income Taxes***

The differencesin income taxes result from a combination of the changes in income and theimpact of the recognition of tax credits on the effective tax rate. We includean analysis of the changes in the effective tax rate in *Note 10*.

Total incometaxes increased $187.1 million in 2006 compared to 2005 primarily due to ahigher level of pre-tax income, including the gain on sale of gas-fired plantsand the gain on initial public offering of CEP, as well as a decrease insynthetic fuel tax credits. We discuss all of these events in the *Significant Events* section.

Total incometaxes increased $45.5 million in 2005 compared to 2004 primarily due to therecognition of $35.9 million in synthetic fuel tax credits in 2004 related to2003 production.

Total incometaxes for BGE decreased $17.7 million in 2006 compared to 2005 mostly due tolower pre-tax income.

Total income taxes for BGE increased $17.4 million in 2005 compared to2004 mostly due to higher pre-tax income.

***Defined BenefitObligations***

We expect tocontribute $125 million to our pension plans in 2007.

At December 31, 2006, werecorded a net after-tax charge to “Accumulated other comprehensive income” of$93.9 million. This net after-tax charge was a result of the following:

 ̈  reducingour additional minimum pension liability, which resulted in an increase to “Accumulatedother comprehensive income” of $75.6 million, and

 ̈  theadoption of SFAS No. 158, *Employers’ Accounting forDefined Benefit Pension and Other Postretirement Plans, an amendment of FASBStatements No. 87, 106 and 132(R)*, which resulted in a decreaseto “Accumulated other comprehensive income” of $169.5 million.

SFAS No. 158, discussed in *Note 1*, creates the potential for additional volatility inaccumulated other comprehensive income. We discuss our defined benefitobligations in more detail in *Note 7*.

 

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**Financial Condition**

**Cash Flows**

The following table summarizes our 2006 cash flows by business segment,as well as our consolidated cash flows for 2006, 2005, and 2004.
| ** **                                                                          | ** ** | **2006 Segment  Cash Flows** | ** ** | **Consolidated  Cash Flows** | ** ** |
|-------------------------------------------------------------------------------------|------------|------------------------------|------------|------------------------------|------------|
| ** **                                                                          | ** ** | **Merchant**                 | ** ** | **Regulated**                | ** ** | **Other** | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                          | ** ** | ***(In millions)***     | ** ** |
| **Operating  Activities**                                                           |       |                         |       |                         |       |   |   |   |   |   |   |   |   |   |   |
| Net income                                                                          |       | $                            | 767.0      |                         |       | $ | 157.2 |   |   | $ | 12.2 |   | $ | 936.4 |   | $ | 623.1 |   | $ | 539.7 |   |
| Non-cash adjustments to net income                                                  |       | 160.3                        |       |                         | 13.9       |   |   | 21.2 |   | 195.4 |   | 746.0 |   | 905.3 |   |
| Changes in working capital                                                          |       | (858.0                       | )          |                         | 108.4      |   |   | 77.7 |   | (671.9 | ) | (775.3 | ) | (319.6 | ) |
| Defined benefit obligations*                                                        |       |                         |       |                         |       |   |   |   |   | 40.5 |   | 3.4 |   | (13.6 | ) |
| Other                                                                               |       | (0.8                         | )          |                         | (30.1      | ) |   | 55.8 |   | 24.9 |   | 30.0 |   | (25.0 | ) |
| Net cash  provided by operating activities                                          |       | 68.5                         |       |                         | 249.4      |   |   | 166.9 |   | 525.3 |   | 627.2 |   | 1,086.8 |   |
| **Investing  Activities**                                                           |       |                         |       |                         |       |   |   |   |   |   |   |   |   |   |   |
| Investments in property, plant and  equipment                                       |       | (613.4                       | )          |                         | (332.5     | ) |   | (17.0 | ) | (962.9 | ) | (760.0 | ) | (703.6 | ) |
| Asset acquisitions and business  combinations, net of cash acquired                 |       | (137.6                       | )          |                         | —     |   |   | — |   | (137.6 | ) | (237.2 | ) | (457.3 | ) |
| Investment in nuclear decommissioning trust  fund securities                        |       | (394.6                       | )          |                         | —     |   |   | — |   | (394.6 | ) | (370.8 | ) | (424.2 | ) |
| Proceeds from nuclear decommissioning trust  fund securities                        |       | 385.8                        |       |                         | —     |   |   | — |   | 385.8 |   | 353.2 |   | 402.2 |   |
| Net proceeds from sale of gas-fired plants and  discontinued operations             |       | 1,630.7                      |       |                         | —     |   |   | — |   | 1,630.7 |   | 289.4 |   | 72.7 |   |
| Issuances of loans receivable                                                       |       | (65.4                        | )          |                         | —     |   |   | — |   | (65.4 | ) | (82.8 | ) | — |   |
| Sale of investments and other assets                                                |       | 23.4                         |       |                         | —     |   |   | 20.5 |   | 43.9 |   | 14.4 |   | 36.1 |   |
| Contract and portfolio acquisitions                                                 |       | (2.3                         | )          |                         | —     |   |   | — |   | (2.3 | ) | (336.2 | ) | — |   |
| Other investments                                                                   |       | 57.0                         |       |                         | 10.3       |   |   | (4.8 | ) | 62.5 |   | (44.0 | ) | (78.6 | ) |
| Net cash  provided by (used in) investing activities                                |       | 883.6                        |       |                         | (322.2     | ) |   | (1.3 | ) | 560.1 |   | (1,174.0 | ) | (1,152.7 | ) |
| **Cash  flows from operating activities less cash flows from investing activities** | ** ** | $                            | 952.1      |                         |       | $ | (72.8 | ) |   | $ | 165.6 |   | 1,085.4 |   | (546.8 | ) | (65.9 | ) |
| **Financing  Activities***                                                          |       |                         |       |                         |       |   |   |   |   |   |   |   |   |   |   |
| Net issuance (repayment) of debt                                                    |       |                         |       |                         |       |   |   |   |   | 242.2 |   | (339.6 | ) | (152.8 | ) |
| Proceeds from issuance of common stock                                              |       |                         |       |                         |       |   |   |   |   | 84.4 |   | 96.9 |   | 293.9 |   |
| Common stock dividends paid                                                         |       |                         |       |                         |       |   |   |   |   | (264.0 | ) | (228.8 | ) | (189.7 | ) |
| Proceeds from initial public offering of  CEP LLC                                   |       |                         |       |                         |       |   |   |   |   | 101.3 |   | — |   | — |   |
| Proceeds from contract and portfolio  acquisitions                                  |       |                         |       |                         |       |   |   |   |   | 221.3 |   | 1,026.9 |   | 117.5 |   |
| Other                                                                               |       |                         |       |                         |       |   |   |   |   | 5.5 |   | 98.1 |   | (18.0 | ) |
| Net cash  provided by financing activities                                          |       |                         |       |                         |       |   |   |   |   | 390.7 |   | 653.5 |   | 50.9 |   |
| Net increase (decrease) in cash and cash  equivalents                               |       |                         |       |                         |       |   |   |   |   | $ | 1,476.1 |   | $ | 106.7 |   | $ | (15.0 | ) |

 

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

***Cash Flows fromOperating Activities***

Cash providedby operating activities was $525.3 million in 2006 compared to$627.2 million in 2005. This $101.9 million decrease was primarilydue to a decrease in non-cash adjustments to net income in 2006, partiallyoffset by favorable changes in net income and working capital.

Non-cashadjustments to net income decreased by $550.6 million in 2006 compared to2005 primarily due to the change in deferred fuel costs of $336.6 millionrelated mostly to the deferred recovery of electricity purchased for resaleunder the BGE rate stabilization plan. We discuss the rate stabilization planin more detail in the *Item 1.—Business—ElectricRegulatory Matters and Competition* section and *Note 1*.In addition, our gains on the sale of gas-fired plants and discontinuedoperations increased $177.6 million in 2006 compared to 2005. We discuss thisin more detail in *Note 2*.

Changes inworking capital had a negative impact of $671.9 million on cash flow fromoperations in 2006 compared to a negative impact of $775.3 million in2005. The negative impact of $671.9 million related to working capital wasprimarily due to the commodity price environment and increased risk managementand trading activities that resulted in an increase of approximately$630 million in net cash collateral requirements, primarily forrequirements on exchange-settled transactions. This increase in cashcollateral requirements was accompanied by a decrease in our letters of creditrequirements.

Cash providedby operating activities was $627.2 million in 2005 compared to$1,086.8 million in 2004. Net income was higher by $83.4 million in2005 compared to 2004. Non-cash adjustments to net income were$159.3 million lower in 2005 compared to 2004. The decrease in non-cashadjustments 

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to net income was primarily due to the reclassification of$72.6 million of proceeds from derivative power sales contracts asfinancing activities under SFAS No. 149, *Amendmentof FASB Statement No. 133 on Derivative and Hedging Activities*and $63.9 million related to the impact of discontinued operations.

Changes in working capital had a negative impact of $775.3 millionon cash flow from operations in 2005 compared to a negative impact of$319.6 million in 2004. The decrease of $455.7 million was due to a$598 million unfavorable change in working capital primarily related toour accounts receivable, accounts payable, and fuel stocks mostly due to highercommodity prices, increased value of emissions credits, and business growth. Thiswas partially offset by an increase of $142 million of net cash collateralreceived, which was also due to higher commodity prices.

***Cash Flows fromInvesting Activities***

Cash providedby investing activities was $560.1 million in 2006 compared to cash usedin investing activities $1,174.0 million in 2005. The $1,734.1 millionfavorable change in 2006 compared to 2005 was primarily due to the increase inproceeds from sale of gas-fired plants and discontinued operations of $1,341.3million and a decrease of $333.9 million in cash paid for contract andportfolio acquisitions. We discuss contract and portfolio acquisitions in moredetail below.

Cash used in investing activities was $1,174.0 million in 2005compared to $1,152.7 million in 2004. The slight increase in cash used ininvesting activities was mostly due to $336.2 million of cash paid forcontract and portfolio acquisitions and $82.8 million in issuances ofloans receivable related primarily to a customer contract restructuring. Wediscuss contract and portfolio acquisitions in more detail below, and thecustomer contract restructuring is discussed in more detail in *Note 4.* These increases in cash usedin 2005 compared to 2004 were partially offset by less cash paid for assetacquisitions and business combinations of $220.1 million in 2005 comparedto 2004 and an increase in cash proceeds from the sale of discontinuedoperations of $216.7 million, primarily due to the sale of Oleander andour other nonregulated international investments in 2005 as discussed in moredetail in *Note 2*.

***Cash Flows fromFinancing Activities***

Cash providedby financing activities was $390.7 million in 2006 compared to$653.5 million in 2005. The decrease of $262.8 million in cashprovided in 2006 compared to 2005 was primarily due to a decrease in proceedsfrom acquired contracts of $805.6 million, a decrease in other financingactivities of $92.6 million, and a $35.2 million increase in our dividends paidin 2006 compared to 2005. We discuss the proceeds from acquired contractsbelow. These decreases were partially offset by a net increase in cash relatedto changes in short-term borrowings and long-term debt of $581.8 million and$101.3 million in proceeds from the initial public offering of CEP.

Cash provided by financing activities was $653.5 million in 2005compared to $50.9 million in 2004. The increase in 2005 compared to 2004was mostly due to an increase in proceeds from contract and portfolioacquisitions of $909.4 million. We discuss proceeds from contract andportfolio acquisitions in more detail below. This increase in cash provided byfinancing activities was partially offset by a reduction in proceeds fromissuances of common stock, an increase in cash used for repayments of debt, andhigher dividend payments in 2005 compared to 2004.

***Contract andPortfolio Acquisitions***

During 2006, 2005, and 2004, our merchant energy business acquiredseveral pre-existing energy purchase and sale agreements, which generatedsignificant cash flows at the inception of the contracts. These agreements hadcontract prices that differed from market prices at closing, which resulted incash payments from the counterparty at the acquisition of the contract. Wereceived net cash of $219.0 million in 2006, $690.7 million in 2005,and $117.5 million in 2004 for various contract and portfolio acquisitions. Wereflect the underlying contracts on a gross basis as assets or liabilities inour Consolidated Balance Sheets depending on whether they were at above-or below-market prices at closing; therefore, we have also reflected themon a gross basis in cash flows from investing and financing activities in ourConsolidated Statements of Cash Flows as follows:
| ***Year ended December 31,***                                 | ** ** | **2006**                 | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------------------------------------------------------------------------|------------|--------------------------|------------|----------|------------|----------|------------|
| ** **                                                                   | ** ** | ***(In millions)*** | ** ** |
| Financing activities—proceeds from contract and portfolio  acquisitions | ** ** | **$**                    | **221.3**  |     | $          | 1,026.9  |       | $ | 117.5 |   |
| Investing activities—contract and portfolio acquisitions                | ** ** | **(2.3**                 | **)**      | (336.2   | )          | —   |       |
| Cash flows from contract and portfolio acquisitions                          | ** ** | **$**                    | **219.0**  |     | $          | 690.7    |       | $ | 117.5 |   |

 

We record theproceeds we receive to acquire energy purchase and sale agreements as afinancing cash inflow because it constitutes a prepayment for a portion of themarket price of energy, which we will buy or sell over the term of theagreements and does not represent a cash inflow from current period operatingactivities. For those acquired contracts that are derivatives, we record theongoing cash flows related to the contract with the counterparties as financingcash inflows in accordance with SFAS No. 149.

We discuss certain of these contract and portfolio acquisitions in moredetail in *Note 4* and *Note 5*.

**Security Ratings**

Independentcredit-rating agencies rate Constellation Energy’s and BGE’s fixed-incomesecurities. The ratings indicate the agencies’ assessment of each company’sability to pay interest, distributions, dividends, and principal on thesesecurities. These ratings affect how much it will cost each company to sellthese securities. Generally, the better the rating, the lower the cost of thesecurities to each company when they sell them.

The factorsthat credit rating agencies consider in establishing Constellation Energy’s andBGE’s credit ratings include, but are not limited to, cash flows, liquidity,business 

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risk profile, and the amount of debt as a component of totalcapitalization.

At the date of this report, our creditratings were as follows:
| ** **                  | ** ** | **Standard  & Poors  Rating  Group** | ** ** | **Moody’s  Investors  Service** | ** ** | **Fitch-  Ratings** | ** ** |
|-----------------------------|------------|-----------------------------------------------|------------|--------------------------------------|------------|---------------------|------------|
| **Constellation Energy**    |       |                                          |       |                                 |       |                |       |   |   |   |   |   |   |
| Commercial  Paper           |       |                                          | A-2        |                                 |       |                | P-2        |   |   |   | F-2 |   |   |
| Senior  Unsecured Debt      |       |                                          | BBB+       |                                 |       |                | Baa1       |   |   |   | BBB+ |   |   |
| **BGE**                     |       |                                          |       |                                 |       |                |       |   |   |   |   |   |   |
| Commercial  Paper           |       |                                          | A-2        |                                 |       |                | P-2        |   |   |   | F-2 |   |   |
| Mortgage  Bonds             |       |                                          | A          |                                 |       |                | Baa1       |   |   |   | A |   |   |
| Senior  Unsecured Debt      |       |                                          | BBB+       |                                 |       |                | Baa2       |   |   |   | A- |   |   |
| Trust  Preferred Securities |       |                                          | BBB-       |                                 |       |                | Baa3       |   |   |   | BBB+ |   |   |
| Preference Stock            |       |                                          | BBB-       |                                 |       |                | Ba1        |   |   |   | BBB+ |   |   |

 

**Available Sourcesof Funding**

We continuously monitor our liquidity requirements and believe that ourcredit facilities and access to the capital markets provide sufficientliquidity to meet our business requirements. We discuss our available sourcesof funding in more detail below.

***Constellation Energy***

In addition to our cash balance, we have a commercial paper programunder which we can issue short-term notes to fund our subsidiaries. At December 31,2006, we had approximately $4,550 million of credit under severalfacilities. These facilities include:

 ̈  a $1.0 billion 364-day credit facility expiringOctober 2007,

 ̈  a $200.0 million 364-day credit facilityexpiring December 2007,

 ̈  a $1.5 billion five-year revolving creditfacility that expires in March 2010,

 ̈  a $1.1 billion five-year revolving creditfacility that expires in November 2010, and

 ̈  a $750.0 million five-year revolving creditfacility that expires in November 2010.

We enter intothese facilities to ensure adequate liquidity to support our operations.Currently, we use the facilities to issue letters of credit primarily for ourmerchant energy business. Additionally, we can borrow directly from the banksor use the facilities to allow the issuance of commercial paper with the exceptionof the $1.0 billion 364-day facility, which only supports $500.0 millionof letters of credit and the $200.0 million 364-day facility, which onlysupports letters of credit.

These revolvingcredit facilities allow the issuance of letters of credit up to$4,050 million. At December 31, 2006, letters of credit that totaled$1,648 million were issued under all of our facilities, which results inapproximately $2.9 billion of unused credit facilities.

We expect to fund future acquisitions with an overall goal ofmaintaining a strong investment grade credit profile.

***Merchant Energy***

In November 2006,we completed the initial public offering of CEP and received $101.3 million ofnet cash proceeds. We discuss the initial public offering in more detail in *Note 2*. We may obtainadditional cash by completing sales of our other natural gas properties. Ourability to complete these sales will depend on market conditions, and we cannotgive assurances that these sales could be completed.

On October 31,2006, CEP entered into a $200.0 million secured revolving credit facility. Thecredit facility will mature on October 31, 2010. We discuss this long-termfacility in more detail in *Note 9*.

In December 2006, we completed the sale of our gas-fired plantsand received $1.6 billion in cash. The proceeds from the sale are expected tobe applied to reduce debt and invest in our business or repurchase equity. Wediscuss this sale in more detail in *Note 2*.

***BGE***

BGE currentlymaintains a $400.0 million five-year revolving credit facility expiring in2011. BGE can borrow directly from the banks or use the facilities to allowcommercial paper to be issued. As of December 31, 2006, BGE had nooutstanding commercial paper, which results in $400.0 million in unusedcredit facilities.

Pursuant to Senate Bill 1, BGE is permitted to recover deferred costsassociated with the residential electric rate deferral by issuing ratestabilization bonds after January 1, 2007 that securitize the deferredcosts. In December 2006, the Maryland PSC issued an order, which allowsBGE to issue bonds in an aggregate principal amount of approximately $630 million,subject to adjustment. We currently intend to issue such bonds in 2007. Wediscuss Senate Bill 1 in more detail in *Item 1. Business—ElectricRegulatory Matters and Competition*section.

***OtherNonregulated Businesses***

If we can get a reasonable value for our remaining real estate projectsand other investments, additional cash may be obtained by selling them. Ourability to sell or liquidate assets will depend on market conditions, and wecannot give assurances that these sales or liquidations could be made.

**Capital Resources**

Our actualconsolidated capital requirements for the years 2004 through 2006, along withthe estimated annual amount for 2007, are shown in the table on the next page.

We will continue to have cash requirements for:

 ̈  working capital needs,

 ̈  payments of interest, distributions, and dividends,

 ̈  capital expenditures, and

 ̈  the retirement of debt and redemption of preferencestock.

Capital requirements for 2007 and 2008 include estimates of spendingfor existing and anticipated projects. We continuously review and modify thoseestimates. Actual requirements may vary from the estimates included in thetable on the next page because of a number of factors including:

 ̈  regulation, legislation, and competition,

 ̈  BGE load requirements,

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 ̈  environmental protection standards,

 ̈  the type and number of projects selected forconstruction or acquisition,

 ̈  the effect of market conditions on those projects,

 ̈  the cost and availability of capital,

 ̈  the availability of cash from operations, and

 ̈  business decisions to invest in capital projects.

Our estimates are also subject to additional factors. Please see the *Forward Looking Statements* and *Item 1A**. Risk Factors*sections.
| ** **                                  | ** ** | **2004**                 | ** ** | **2005**   | ** ** | **2006**   | ** ** | **2007**   | ** ** |
|---------------------------------------------|------------|--------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                  | ** ** | ***(In millions)*** | ** ** |
| **Nonregulated Capital Requirements:**      | ** ** | ** **               | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Merchant energy (excludes  acquisitions)    |       | ** **               | ** ** |       |       |       |       |       |       |
| Generation plants                           |       | $                        | 182        | ** ** | $          | 182        |       | $          | 235        |   | $ | 235 |   |
| Nuclear fuel                                |       | 133                      | ** ** | 130        |       | 137        |       | 150        |       |
| Environmental controls                      |       | —                   | ** ** | 1          |       | 17         |       | 330        |       |
| Portfolio  acquisitions/investments         |       | 11                       | ** ** | 231        |       | 227        |       | 550        |       |
| Technology/other                            |       | 129                      | ** ** | 165        |       | 152        |       | 200        |       |
| Total merchant energy  capital requirements |       | 455                      | ** ** | 709        |       | 768        |       | 1,465      |       |
| Other nonregulated  capital requirements    |       | 42                       | ** ** | 32         |       | 21         |       | 10         |       |
| Total nonregulated  capital requirements    |       | 497                      | ** ** | 741        |       | 789        |       | 1,475      |       |
| **Regulated Capital Requirements:**         | ** ** | ** **               | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Regulated electric                          |       | 209                      | ** ** | 241        |       | 297        |       | 380        |       |
| Regulated gas                               |       | 56                       | ** ** | 50         |       | 63         |       | 60         |       |
| Total regulated capital  requirements       |       | 265                      | ** ** | 291        |       | 360        |       | 440        |       |
| **Total capital requirements**              |       | $                        | 762        | ** ** | $          | 1,032      |       | $          | 1,149      |   | $ | 1,915 |   |

*The tableabove does not include amounts related to pre-acquisition capital requirementsbut does include post-acquisition capital requirements. We discuss ouracquisitions in more detail in Note 15.*

As of the date of this report, we have notcompleted our 2008 capital budgeting process, but expect our 2008 capitalrequirements to be approximately $1.7 billion.

Ourenvironmental controls capital requirements are affected by new rules orregulations that require modifications to our facilities. Based on informationcurrently available to us regarding recently issued regulations, we willinstall additional air emission control equipment at certain of our coal-firedgenerating facilities in Maryland and at co-owned coal-fired generatingfacilities in Pennsylvania. We estimate another $800 million of capital spendingfrom 2008-2011 for environmental controls. We discuss environmentalmatters in more detail in *Item 1. Business—EnvironmentalMatters*.

**CapitalRequirements**

***Merchant EnergyBusiness***

Our merchantenergy business’ capital requirements consist of its continuing requirements,including expenditures for:

 ̈  improvements to generatingplants,

 ̈  nuclear fuel costs,

 ̈  upstream gas investments,

 ̈  portfolio acquisitions and otherinvestments,

 ̈  costs of complying with theEnvironmental Protection Agency (EPA), Maryland, and Pennsylvania environmentalregulations and legislation, and

 ̈  enhancements to our informationtechnology infrastructure.

***RegulatedElectric and Gas***

Regulatedelectric and gas construction expenditures primarily include new businessconstruction needs and improvements to existing facilities, including projectsto improve reliability.

**Funding for CapitalRequirements**

***Merchant EnergyBusiness***

Funding for ourmerchant energy business is expected from internally generated funds. Ifinternally generated funds are not sufficient to meet funding requirements, wehave  available sources from commercialpaper issuances, issuances of long-term debt and equity, leases, and otherfinancing activities.

The projectsthat our merchant energy business develops typically require substantialcapital investment. Many of the qualifying facilities and independent powerprojects that we have an interest in are financed primarily with non-recoursedebt that is repaid from the project’s cash flows. This debt is collateralizedby interests in the physical assets, major project contracts and agreements,cash accounts and, in some cases, the ownership interest in that project.

We expect to fund acquisitions with a mixture of debt and equity withan overall goal of maintaining a strong investment grade credit profile.

***RegulatedElectric and Gas***

Funding forregulated electric and gas capital expenditures is expected from internallygenerated funds. If internally generated funds are not sufficient to meetfunding requirements, we have  availablesources from commercial paper issuances, available capacity under creditfacilities, the issuance of long-term debt, trust preferred securities, orpreference stock, and/or from time to time equity contributions from ConstellationEnergy. We discuss BGE’s planned issuance of rate stabilization bonds in the *Available Sources of Funding* section. BGE also participatesin a cash pool administered by Constellation Energy as discussed in *Note 16*.

***OtherNonregulated Businesses***

Funding for our other nonregulated businessesis expected from internally generated funds. If internally generated funds arenot sufficient to meet funding requirements, we have  available sources from commercial paperissuances, issuances of long-term debt of Constellation Energy, sales ofsecurities and assets, and/or from time to time equity contributions fromConstellation Energy.

Our ability to sell or liquidate securities and non-core assets willdepend on market conditions, and we cannot give assurances that these sales orliquidations could be made. We discuss our remaining non-core assets and marketconditions in the *Results of Operations—OtherNonregulated Businesses* section.

**Contractual PaymentObligations and Committed Amounts**

We enter intovarious agreements that result in contractual payment obligations in connectionwith our business activities. These obligations primarily relate to ourfinancing 

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arrangements(such as long-term debt, preference stock, and operating leases), purchases ofcapacity and energy to support the growth in our merchant energy businessactivities, and purchases of fuel and transportation to satisfy the fuelrequirements of our power generating facilities.

Our total contractual payment obligations asof December 31, 2006, increased $2.4 billion compared to 2005primarily due to an increase in fuel and transportationobligations and long-term debt. Our fuel and transportation obligationsincreased mostly due to new coal contracts related to our merchant energy business. Our long-term debt increased mostly due to theissuance of BGE Notes, offset in part by repayments made during the year. Wedetail our contractual payment obligations as of December 31, 2006 in thefollowing table:
|                                               | ** ** | **Payments**             | ** ** |
|-----------------------------------------------|------------|--------------------------|------------|
| ** **                                    | ** ** | **2007**                 | ** ** | **2008-  2009** | ** ** | **2010-  2011** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
| ** **                                    | ** ** | ***(In millions)*** | ** ** |
| *Contractual Payment Obligations*             |       |                     |       |   |   |   |   |   |   |   |   |
| Long-term debt:1                              |       |                     |       |   |   |   |   |   |   |   |   |   |   |
| Nonregulated                                  |       |                     |       |   |   |   |   |   |   |   |   |   |   |
| Principal                                     |       | $                        | 620.5      |   | $ | 507.7 |   | $ | 58.8 |   |   | $ | 2,203.3 |   |   | $ | 3,390.3 |   |
| Interest                                      |       | 183.9                    |       | 333.6 |   | 286.9 |   |   | 1,276.1 |   |   | 2,080.5 |   |
| Total                                         |       | 804.4                    |       | 841.3 |   | 345.7 |   |   | 3,479.4 |   |   | 5,470.8 |   |
| BGE                                           |       |                     |       |   |   |   |   |   |   |   |   |   |   |
| Principal                                     |       | 121.4                    |       | 306.1 |   | 22.0 |   |   | 1,267.2 |   |   | 1,716.7 |   |
| Interest                                      |       | 97.3                     |       | 162.6 |   | 155.7 |   |   | 1,408.7 |   |   | 1,824.3 |   |
| Total                                         |       | 218.7                    |       | 468.7 |   | 177.7 |   |   | 2,675.9 |   |   | 3,541.0 |   |
| BGE preference stock                          |       | —                   |       | — |   | — |   |   | 190.0 |   |   | 190.0 |   |
| Operating leases2                             |       | 186.0                    |       | 222.3 |   | 153.4 |   |   | 391.6 |   |   | 953.3 |   |
| Purchase obligations:3                        |       |                     |       |   |   |   |   |   |   |   |   |   |   |
| Purchased capacity and energy4                |       | 367.1                    |       | 755.5 |   | 271.8 |   |   | 526.0 |   |   | 1,920.4 |   |
| Fuel and transportation                       |       | 2,866.5                  |       | 1,867.3 |   | 475.9 |   |   | 894.4 |   |   | 6,104.1 |   |
| Other                                         |       | 103.2                    |       | 68.0 |   | 9.6 |   |   | 26.1 |   |   | 206.9 |   |
| Other noncurrent liabilities:                 |       |                     |       |   |   |   |   |   |   |   |   |   |   |
| Pension benefits5                             |       | 128.8                    |       | 71.5 |   | 144.0 |   |   | — |   |   | 344.3 |   |
| Postretirement and post employment  benefits6 |       | 35.2                     |       | 81.1 |   | 91.5 |   |   | 290.7 |   |   | 498.5 |   |
| Total  contractual payment obligations        |       | $                        | 4,709.9    |   | $ | 4,375.7 |   | $ | 1,669.6 |   |   | $ | 8,474.1 |   |   | $ | 19,229.3 |   |

*1    Amountsin long-term debt reflect the original maturity date. Investors mayrequire us to repay $384.3 million early through put options and remarketingfeatures. Interest on variable rate debt is included based on the December 31,2006 forward curve for interest rates.*

*2    Ouroperating lease commitments include future payment obligations under certainpower purchase agreements as discussed further in Note 11.*

*3    Contractsto purchase goods or services that specify all significant terms. Amountsrelated to certain purchase obligations are based on future purchaseexpectations which may differ from actual purchases.*

*4    Ourcontractual obligations for purchased capacity and energy are shown on a grossbasis for certain transactions, including both the fixed payment portions oftolling contracts and estimated variable payments under unit-contingentpower purchase agreements.*

*5**    Amountsrelated to pension benefits reflect our current 5-year forecast forcontributions for our qualified pension plans and participant payments for ournonqualified pension plans. Refer to Note 7 for more detail on our pensionplans.*

*6**   Amounts related to postretirement andpostemployment benefits are for unfunded plans and reflect present valueamounts consistent with the determination of the related liabilities recordedin our Consolidated Balance Sheets as discussed in Note 7.*

***Termination ofMerger with FPL Group, Inc.***

In connection with the termination of the merger agreement with FPLGroup, there are contingencies relating to certain types of transactionsentered into prior to September 30, 2007. We discuss these contingenciesin *Note 15*.

**Liquidity Provisions**

In many cases,customers of our merchant energy business rely on the creditworthiness ofConstellation Energy. A decline below investment grade by Constellation Energywould negatively impact the business prospects of that operation.

We regularlyreview our liquidity needs to ensure that we have adequate facilities availableto meet collateral requirements. This includes having liquidity available tomeet margin requirements for our wholesale marketing, risk management, andtrading operation and our retail competitive supply activities.

We have certainagreements that contain provisions that would require additional collateralupon credit rating decreases in the senior unsecured debt of ConstellationEnergy. Decreases in Constellation Energy’s credit ratings would not trigger anearly payment on any of our credit facilities.

Under counterparty contracts related to our wholesale marketing, riskmanagement, and trading operation, we are obligated to post collateral ifConstellation Energy’s senior unsecured credit ratings declined belowestablished contractual levels. Based on contractual provisions atDecember 31, 2006, we estimate that if Constellation Energy’s seniorunsecured debt were downgraded we would have the following additionalcollateral obligations:
| **Credit Ratings  Downgraded to** | ** ** | **Level  Below  Current  Rating** | ** ** | **Incremental  Obligations** | ** ** | **Cumulative  Incremental  Obligations** | ** ** |
|---------------------------------------------|------------|-----------------------------------|------------|------------------------------|------------|------------------------------------------|------------|
| ** **                                  | ** ** | ** **                        | ** ** | ***(In millions)***     | ** ** |
| BBB/Baa2                                    |       |                              | 1          |                         |       |                                     | $          | 495 |   |   |   | $ | 495 |   |   |
| BBB-/Baa3                                   |       |                              | 2          |                         |       |                                     | 246        |   |   |   | 741 |   |   |
| Below investment grade                      |       |                              | 3          |                         |       |                                     | 547        |   |   |   | 1,288 |   |   |

 

Based on marketconditions and contractual obligations at the time of a downgrade, we could berequired to post collateral in an amount that could exceed the amountsspecified above, which could be material. We discuss our credit ratings in the *Security Ratings* section and our credit facilities in the *Available Sources of Funding* section.

The creditfacilities of Constellation Energy and BGE have limited material adverse changeclauses that only consider a material change in financial condition and are notdirectly affected by decreases in credit ratings. If these clauses are invoked,the lending institutions can decline to make new advances or issue new lettersof credit, but cannot accelerate the payment of existing amounts outstanding.The long-term debt indentures of Constellation Energy and BGE do not containmaterial adverse change clauses or financial covenants.

Certain creditfacilities of Constellation Energy contain a provision requiring ConstellationEnergy to maintain a ratio of debt to capitalization equal to or less than 65%.At December 31, 2006, the debt to capitalization ratios as defined in thecredit agreements were no greater than 48%. The credit agreement of BGEcontains a provision requiring BGE to maintain a ratio of debt tocapitalization equal to or less than 65%. At December 31, 2006, the debtto capitalization ratio for BGE as defined in this credit agreement was 49%. AtDecember 31, 2006, no amount was outstanding under this agreement.

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Failure byConstellation Energy, or BGE, to comply with these provisions could result inthe acceleration of the maturity of the debt outstanding under thesefacilities. The credit facilities of Constellation Energy contain usual andcustomary cross-default provisions that apply to defaults on debt byConstellation Energy and certain subsidiaries over a specified threshold.

The BGE creditfacility also contains usual and customary cross-default provisions thatapply to defaults on debt by BGE over a specified threshold. The indenturepursuant to which BGE has issued and outstanding mortgage bonds provides that adefault under any debt instrument issued under the indenture may cause adefault of all debt outstanding under such indenture.

ConstellationEnergy also provides credit support to Calvert Cliffs, Nine Mile Point, andGinna to ensure these plants have funds to meet expenses and obligations tosafely operate and maintain the plants.

Pursuant toSenate Bill 1 and an order issued by the Maryland PSC, BGE is permitted torecover deferred costs associated with the residential electric rate deferralafter January 1, 2007, including through the issuance of ratestabilization bonds that securitize the deferred costs. We discuss Senate Bill1 in more detail in *Item 1.—Business—ElectricRegulatory Matters and Competition*section and the ratestabilization bonds in *Available Sources ofFunding* section.

We discuss our short-term credit facilities in *Note 8*, long-term debt in *Note 9*, lease requirements in *Note 11*, and commitments andguarantees in *Note 12*.

**Off-Balance SheetArrangements**

For financingand other business purposes, we utilize certain off-balance sheet arrangementsthat are not reflected in our Consolidated Balance Sheets. Such arrangements donot represent a significant part of our activities or a significant ongoingsource of financing.

We use these arrangements when they enable us to obtain financing orexecute commercial transactions on favorable terms. As of December 31,2006, we have no material off-balance sheet arrangements including:

 ̈  guaranteeswith third-parties that are subject to the initial recognition andmeasurement requirements of FASB Interpretation No. 45, *Guarantor’s Accounting and Disclosure Requirementsfor Guarantees, Including Indirect Guarantees of Indebtedness to Others*,

 ̈  retainedinterests in assets transferred to unconsolidated entities,

 ̈  derivativeinstruments indexed to our common stock, and classified as equity, or

 ̈  variableinterests in unconsolidated entities that provide financing, liquidity, marketrisk or credit risk support, or engage in leasing, hedging or research anddevelopment services.

At December 31,2006, Constellation Energy had a total of $11,277.3 million in guaranteesoutstanding, of which $10,001.8 million related to our competitive supplyactivities. These amounts do not represent incremental consolidatedConstellation Energy obligations; rather, they primarily represent parentalguarantees of certain subsidiary obligations to third parties. These guaranteesare put into place in order to allow our subsidiaries the flexibility needed toconduct business with counterparties without having to post other forms ofcollateral. While the stated limit of these guarantees is$10,001.8 million, our calculated fair value of obligations for commercialtransactions covered by these guarantees was $2,190.6 million at December 31,2006. If the parent company was required to fund these subsidiary obligations,the total amount based on December 31, 2006 market prices would be$2,190.6 million. For those guarantees related to our mark-to-market energy orrisk management liabilities, the fair value of the obligation is recorded inour Consolidated Balance Sheets. We believe it is unlikely that we would berequired to perform or incur any losses associated with guarantees of oursubsidiaries’ obligations.

We discuss ourother guarantees in *Note 12*and our significant variable interests in *Note 4*.

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**Market Risk**

We are exposedto various risks, including, but not limited to, energy commodity price andvolatility risk, credit risk, interest rate risk, equity price risk, foreignexchange risk, and operations risk. Our risk management program is based onestablished policies and procedures to manage these key business risks with a strongfocus on the physical nature of our business. This program is predicated on astrong risk management culture combined with an effective system of internalcontrols.

The AuditCommitteeof the Board of Directors periodically reviews compliance with our riskparameters, limits and trading guidelines, and our Board of Directors hasestablished a value at risk limit. We have a Risk Management Division that isresponsible for monitoring the key business risks, enforcing compliance withrisk management policies and risk limits, as well as managing credit risk. TheRisk Management Division reports to the Chief Risk Officer (CRO) who providesregular risk management updates to the Audit Committee and the Board ofDirectors.

We have a Risk Management Committee (RMC) that is responsible forestablishing risk management policies, reviewing procedures for theidentification, assessment, measurement and management of risks, and themonitoring and reporting of risk exposures. The RMC meets on a regular basisand is chaired by the Vice Chairman of Constellation Energy & Chairmanof Constellation Energy Commodities Group, and consists of our Chief ExecutiveOfficer, our Chief Financial Officer and Chief Administrative Officer, ourExecutive Vice President of Corporate Strategy and Retail Competitive Supply,the Co-Presidents & Chief Executive Officers of ConstellationEnergy Commodities Group, the President of Constellation Generation Group andthe Chief Risk Officer. In addition, the CRO coordinates with the risk managementcommittees at the major operating subsidiaries that meet regularly to identify,assess, and quantify material risk issues and to develop strategies to managethese risks.

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**Interest Rate Risk**

We are exposedto changes in interest rates as a result of financing through our issuance ofvariable-rate and fixed-rate debt and certain related interest rate swaps. Wemay use derivative instruments to manage our interest rate risks.

In December 2006,in order to manage the exposure to fluctuations in interest rates on variablerate debt, CEP entered into a pay fixed and receive floating interest rate swaprelating to $16.5 million of its outstanding debt.

In July 2004,to optimize the mix of fixed and floating-rate debt, we entered into interestrate swaps relating to $450.0 million of our long-term debt. These fairvalue hedges effectively convert our current fixed-rate debt to a floating-rateinstrument tied to the three month London Inter-Bank Offered Rate. Includingthe $450.0 million in interest rate swaps, approximately 14% of ourlong-term debt is floating-rate.

We discuss ouruse of derivative instruments to manage our interest rate risk in more detailin *Note 13*.

The following table provides information about our debt obligationsthat are sensitive to interest rate changes:

 

***Principal Payments and Interest Rate Detailby Contractual Maturity Date***
| ** **            | ** ** | **2007**                              | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **Thereafter** | ** ** | **Total** | ** ** | **Fair value at  December 31,  2006** | ** ** |
|-----------------------|------------|---------------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|------------------------------------------------------|------------|
| ** **            | ** ** | ***(Dollars in millions)*** | ** ** |
| **Long-term debt**    |       |                                  |       |     |       |     |       |     |       |     |       |           |       |      |       |                                                 |       |   |   |
| Variable-rate debt    |       | $                                     | —     |     | $          | —   |       | $        | —     |     | $          | 5.5            |       | $         | 36.0       |                                                 | $          | 681.7 |   | $ | 723.2 |   |   | $ | 723.2 |   |   |
| Average interest rate |       | —                                | %          | —   | %          | —   | %          | 6.63     | %          | 3.55     | %          | 5.50           | %          | 5.52      | %          |                                                 |       |   |   |
| Fixed-rate debt       |       | $                                     | 741.9      | (A)      | $          | 301.1    |       | $        | 512.7      |     | $          | 16.8           |       | $         | 22.5       |                                                 | $          | 2,788.8 |   | $ | 4,383.8 |   |   | $ | 4,513.8 |   |   |
| Average interest rate |       | 6.47                                  | %          | 6.09     | %          | 6.13     | %          | 6.60     | %          | 6.63     | %          | 6.41           | %          | 6.55      | %          |                                                 |       |   |   |

 

*(A)**           Amountexcludes $384.3 million of long-term debt that contains certain putoptions under which lenders could potentially require us to repay the debtprior to maturity of which $136.9 million is classified as current portionof long-term debt in our Consolidated Balance Sheets and in our ConsolidatedStatements of Capitalization.*

**Commodity Risk**

We are exposed to the impact of market fluctuations in the price andtransportation costs of electricity, natural gas, coal, and other commodities.These risks arise from our ownership and operation of power plants, theload-serving activities of BGE and our competitive supply operations, and ourorigination, risk management, and trading activities. We discuss these risksseparately for our merchant energy and our regulated businesses below.

***Merchant EnergyBusiness***

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

*CommodityPrices*

Commodity price risk arises from:

 ̈  thepotential for changes in the price of, and transportation costs for,electricity, natural gas, coal, and other commodities,

 ̈  thevolatility of commodity prices, and

 ̈  changesin interest rates and foreign exchange rates.

A number of factors associated with the structure and operation of theenergy markets significantly influence the level and volatility of prices forenergy commodities and related derivative products. We use such commodities andcontracts in our merchant energy business, and if we do not properly hedge theassociated financial exposure, this commodity price volatility could affect ourearnings. These factors include:

 ̈  seasonal,daily, and hourly changes in demand,

 ̈  extremepeak demands due to weather conditions,

 ̈  availablesupply resources,

 ̈  transportationavailability and reliability within and between regions,

 ̈  locationof our generating facilities relative to the location of our load-servingobligations,

 ̈  proceduresused to maintain the integrity of the physical electricity system duringextreme conditions,

 ̈  changesin the nature and extent of federal and state regulations, and

 ̈  geopoliticalconcerns affecting global supply of oil and natural gas.

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

 ̈  weatherconditions,

 ̈  marketliquidity,

 ̈  capabilityand reliability of the physical electricity and gas systems, and

 ̈  thenature and extent of electricity deregulation.

Additionally, we have fuel requirements that are subject to futurechanges in coal, natural gas, and oil prices. Our power generation facilitiespurchase fuel under contracts or in the spot market. Fuel prices may bevolatile, and the price that can be obtained from power sales may not change atthe same rate or in the same direction as changes in fuel costs. This couldhave a material adverse impact on our financial results.

*Supply andDemand Risk*

We are exposedto the risk that available sources of supply may differ from the amount ofpower demanded by our customers 

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under fixed-priceload-serving contracts. During periods of high demand, our power supplies maybe insufficient to serve our customers’ needs and could require us to purchaseadditional energy at higher prices. Alternatively, during periods of lowdemand, our power supplies may exceed our customers’ needs and could result inus selling that excess energy at lower prices. Either of those circumstancescould have a negative impact on our financial results.

We are also exposed to variations in the prices and required volumes ofnatural gas, oil, and coal we burn at our power plants to generate electricity.During periods of high demand on our generation assets, our fuel supplies maybe insufficient and could require us to procure additional fuel at higherprices. Alternatively, during periods of low demand on our generation assets,our fuel supplies may exceed our needs, and could result in us selling theexcess fuels at lower prices. Either of these circumstances will have anegative impact on our financial results.

*Operations Risk*

Operations riskis the risk that a generating plant will not be available to produce energy andthe risks related to physical delivery of energy to meet our customers’ needs.If one or more of our generating facilities is not able to produce electricitywhen required due to operational factors, we may have to forego salesopportunities or fulfill fixed-price sales commitments through theoperation of other more costly generating facilities or through the purchase ofenergy in the wholesale market at higher prices. We purchase power fromgenerating facilities we do not own. If one or more of those generatingfacilities were unable to produce electricity due to operational factors, wemay be forced to purchase electricity in the wholesale market at higher prices.This could have a material adverse impact on our financial results.

Our nuclear plants produce electricity at a relatively low marginalcost. The Nine Mile Point facility sells 90% of its output underunit-contingent power purchase agreements (we have no obligation to providepower if the units are not available) to the previous owners. Based on its newcapacity, beginning in 2007, we will sell approximately 80% of Ginna’s outputunder a unit-contingent power purchase agreement to the former owners. However,if an unplanned outage were to occur at Calvert Cliffs during periods whendemand was high, we may have to purchase replacement power at potentiallyhigher prices to meet our obligations, which could have a material adverseimpact on our financial results.

*Risk Managementand Trading*

As part of our overall portfolio, we manage the commodity price risk ofour competitive supply activities and our electric generation facilities,including power sales, fuel and energy purchases, emission credits, interestrate and foreign currency risks, weather risk, and the market risk of outages.In order to manage these risks, we may enter into fixed-price derivativeor non-derivative contracts to hedge the variability in future cash flows fromforecasted sales and purchases of energy, including:

 ̈  forwardcontracts, which commit us to purchase or sell energy commodities in thefuture;

 ̈  futurescontracts, which are exchange-traded standardized commitments to purchaseor sell a commodity or financial instrument, or to make a cash settlement, at aspecific price and future date;

 ̈  swapagreements, which require payments to or from counterparties based upon thedifferential between two prices for a predetermined contractual (notional)quantity; and

 ̈  optioncontracts, which convey the right to buy or sell a commodity, financialinstrument, or index at a predetermined price.

The objectives for entering into such hedges include:

 ̈  fixingthe price for a portion of anticipated future electricity sales at a level thatprovides an acceptable return on our electric generation operations,

 ̈  fixingthe price of a portion of anticipated fuel purchases for the operation of ourpower plants,

 ̈  fixingthe price for a portion of anticipated energy purchases to supply ourload-serving customers, and

 ̈  managingour exposure to interest rate risk and foreign currency exchange risks.

The portion offorecasted transactions hedged may vary based upon management’s assessment ofmarket, weather, operational, and other factors.

While some ofthe contracts we use to manage risk represent commodities or instruments forwhich prices are available from external sources, other commodities and certaincontracts are not actively traded and are valued using other pricing sourcesand modeling techniques to determine expected future market prices, contractquantities, or both. We use our best estimates to determine the fair value ofcommodity and derivative contracts we hold and sell. These estimates considervarious factors including closing exchange and over-the-counter pricequotations, time value, volatility factors, and credit exposure. However, it islikely that future market prices could vary from those used in recordingmark-to-market energy assets and liabilities, and such variations could bematerial.

We measure thesensitivity of our wholesale marketing and risk management mark-to-marketenergy contracts to potential changes in market prices using value at risk.Value at risk is a statistical model that attempts to predict risk of lossbased on historical market price volatility. We calculate value at risk using ahistorical variance/covariance technique that models option positions using alinear approximation of their value. Additionally, we estimate variances andcorrelation using historical commodity price changes over the most recentrolling three-month period. Our value at risk calculation includes allwholesale marketing and risk management mark-to-market energy assets andliabilities, including contracts for energy commodities and derivatives thatresult in physical settlement and contracts that require cash settlement.

The value atrisk calculation does not include market risks associated with activities thatare subject to accrual accounting, primarily our generating facilities and ourcompetitive supply load-serving activities. We manage these risks by monitoringour fuel and energy purchase requirements and our estimated contract salesvolumes compared to associated supply arrangements. We also engage in hedgingactivities to manage these risks. We describe those risks and our hedgingactivities earlier in this section.

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The value at risk amounts below represent thepotential pre-tax loss in the fair value of our wholesale marketing and riskmanagement mark-to-market energy assets and liabilities over one and ten-dayholding periods.
| ***Total Wholesale Value at Risk  For the year ended December 31,*** | ** ** | **2006**                 | ** ** | **2005** | ** ** |
|-------------------------------------------------------------------------------------------------------------------|------------|--------------------------|------------|----------|------------|
| ** **                                                                                                        | ** ** | ***(In millions)*** | ** ** |
| 99% Confidence Level, One-Day Holding Period                                                                      |       |                     |       |     |       |
| Year end                                                                                                          | ** ** | **$**                    | **13.4**   |     | $          | 10.0 |   |
| Average                                                                                                           | ** ** | **16.7**                 |       | 6.1      |       |
| High                                                                                                              | ** ** | **28.0**                 |       | 14.5     |       |
| Low                                                                                                               | ** ** | **9.6**                  |       | 2.4      |       |
| 95% Confidence Level, One-Day Holding Period                                                                      |       |                     |       |     |       |
| Year end                                                                                                          | ** ** | **$**                    | **10.2**   |     | $          | 7.6 |   |
| Average                                                                                                           | ** ** | **12.7**                 |       | 4.7      |       |
| High                                                                                                              | ** ** | **21.3**                 |       | 11.0     |       |
| Low                                                                                                               | ** ** | **7.3**                  |       | 1.8      |       |
| 95% Confidence Level, Ten-Day Holding Period                                                                      |       |                     |       |     |       |
| Year end                                                                                                          | ** ** | **$**                    | **32.3**   |     | $          | 24.1 |   |
| Average                                                                                                           | ** ** | **40.2**                 |       | 14.7     |       |
| High                                                                                                              | ** ** | **67.4**                 |       | 34.9     |       |
| Low                                                                                                               | ** ** | **23.0**                 |       | 5.8      |       |

 

Based on a 99%confidence interval, we would expect a one-day change in the fair value of theportfolio greater than or equal to the daily value at risk approximately oncein every 100 days. In 2006, we did not experience any instance where theactual daily mark-to-market change in portfolio value exceeded the predictedvalue at risk. However, published market studies conclude that exceeding dailyvalue at risk less than seven times in a one-year period is consideredconsistent with a 99% confidence interval.

The table aboveis the value at risk associated with our wholesale marketing, risk management,and trading operation’s mark-to-market energy assets and liabilities, includingboth trading and non-trading activities. We experienced higher value at riskfor the year ended December 31, 2006 compared to the year ended December 31,2005, primarily due to a higher number of economic hedges of accrual positionsand an increase in our trading activities discussed below. We discuss ourmark-to-market results in more detail in the *CompetitiveSupply* section.

The following table details our value at risk for the trading portionof our wholesale marketing and risk management mark-to-market energy assets andliabilities over a one-day holding period at a 99% confidence level for 2006and 2005:
| ***Wholesale Trading Value at Risk  For the year ended December 31,*** | ** ** | **2006**                 | ** ** | **2005** | ** ** |
|---------------------------------------------------------------------------------------------------------------------|------------|--------------------------|------------|----------|------------|
| ** **                                                                                                          | ** ** | ***(In millions)*** | ** ** |
| Average                                                                                                             | ** ** | **$**                    | **11.2**   |     | $          | 5.5 |   |
| High                                                                                                                | ** ** | **17.6**                 |       | 13.3     |       |
|                                                                                                                     |            |                          |            |          |            |  |  |

 

We experiencedhigher value at risk for the year ended December 31, 2006 compared to theyear ended December 31, 2005, for the trading portion of our wholesaletrading portfolio due to increased commodity prices, volatility, and tradingactivity. Our trading positions can be used to manage the commodity price riskof our competitive supply activities and our generation facilities. We alsoengage in trading activities for profit. These activities are managed throughdaily value at risk and stop loss limits and liquidity guidelines.

Due to the inherent limitations of statistical measures such as valueat risk and the seasonality of changes in market prices, the value at riskcalculation may not reflect the full extent of our commodity price riskexposure. Additionally, actual changes in the value of options may differ fromthe value at risk calculated using a linear approximation inherent in ourcalculation method. As a result, actual changes in the fair value ofmark-to-market energy assets and liabilities could differ from the calculatedvalue at risk, and such changes could have a material impact on our financialresults.

***RegulatedElectric Business***

BGE’sresidential base rates were frozen for the six-year period ended June 30,2006, and its commercial and industrial base rates were frozen for a four-yearperiod that ended June 30, 2004. The commodity and transmission componentsof rates were frozen for different time periods depending on the customer typeand service options selected by customers.

Our wholesalemarketing, risk management, and trading operation provided BGE 100% of theenergy and capacity to meet its residential standard offer service obligationsthrough June 30, 2006. Bidding to supply BGE’s standard offer service toall customers will occur from time to time through a competitive biddingprocess approved by the Maryland PSC. Our wholesale marketing, risk management,and trading operation is supplying a portion of BGE’s standard offer serviceobligation to all customers. We discuss standard offer service and the impacton base rates in more detail in *Item 1.Business—Electric Business* section.

BGE may receiveperformance assurance collateral from suppliers to mitigate suppliers’ creditrisks in certain circumstances. Performance assurance collateral is designed toprotect BGE’s potential exposure over the term of the supply contracts and willfluctuate to reflect changes in market prices. In addition to the collateralprovisions, there are supplier “step-up” provisions, where other suppliers canstep in if the early termination of a Full-Requirements Service Agreement witha supplier should occur, as well as specific mechanisms for BGE to otherwisereplace defaulted supplier contracts. All costs incurred by BGE to replace thesupply contract are to be recovered from the defaulting supplier or fromcustomers through rates. Finally, BGE’s exposure to uncollectible expense orcredit risk from customers for the commodity portion of the bill is covered bythe administrative fee included in Provider of Last Resort rates.

Our regulated electric business may enter into electric futures,options, and swaps to hedge its price. We discuss this further in *Note 13*. At December 31, 2006and 2005, our exposure to commodity price risk for our regulated electric businesswas not material.

 

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***Regulated GasBusiness***

Our regulated gas business may enter into gas futures, options, andswaps to hedge its price risk under our market-based rate incentivemechanism and our off-system gas sales program. We discuss this further in *Note 13*. At December 31, 2006and 2005, our exposure to commodity price risk for our regulated gas businesswas not material.

**Credit Risk**

We are exposed to credit risk, primarily through our merchant energybusiness. Credit risk is the loss that may result from counterparties’ nonperformance.We evaluate the credit risk of our wholesale marketing, risk management, andtrading operation and our retail competitive supply activities separately asdiscussed below.

***WholesaleCredit Risk***

We measurewholesale credit risk as the replacement cost for open energy commodity andderivative transactions (both mark-to-market and accrual) adjusted for amountsowed to or due from counterparties for settled transactions. The replacementcost of open positions represents unrealized gains, net of any unrealizedlosses, where we have a legally enforceable right of setoff. We monitor andmanage the credit risk of our wholesale marketing, risk management, and tradingoperation through credit policies and procedures which include an establishedcredit approval process, daily monitoring of counterparty credit limits, theuse of credit mitigation measures such as margin, collateral, or prepaymentarrangements, and the use of master netting agreements.

As of December 31, 2006 and 2005, thecredit portfolio of our wholesale marketing, risk management, and tradingoperation had the following public credit ratings:
| ***At December 31,*** | ** ** | **2006** | ** ** | **2005** | ** ** |
|---------------------------------|------------|----------|------------|----------|------------|
| Rating                          | ** ** |     | ** ** |     |       |   |   |   |   |
| Investment  Grade1              | ** ** |     | **61**     | **%**    |       |   | 53 | % |   |
| Non-Investment  Grade           | ** ** |     | **3**      |     |       |   | 7 |   |   |
| Not Rated                       | ** ** |     | **36**     |     |       |   | 40 |   |   |

*1**      Includescounterparties with an investment grade rating by at least one of the majorcredit rating agencies. If split rating exists, the lower rating is used.*

Our exposure to “Not Rated” counterpartieswas $1.1 billion at December 31, 2006 compared to $1.4 billionat December 31, 2005. This decrease was mostly due to a decrease in ourcredit portfolio related to natural gas and international coal customers thatdo not have public credit ratings. Although not rated, a majority of thesecounterparties are considered investment grade equivalent based on our internalcredit ratings. We utilize internal credit ratings to evaluate thecreditworthiness of our wholesale customers, including those companies that donot have public credit ratings. Based on internal credit ratings, approximately$643.8 million or 59% of the exposure to unrated counterparties was ratedinvestment grade equivalent at December 31, 2006 and approximately$915.7 million or 68% was rated investment grade equivalent at December 31,2005. The following table provides the breakdown of the credit quality of ourwholesale credit portfolio based on our internal credit ratings.
| ***At December 31,*** | ** ** | **2006** | ** ** | **2005**   | ** ** |
|---------------------------------|------------|----------|------------|------------|------------|
| Investment Grade Equivalent     | ** ** |     | **82**     | **%**      |       |   | 80 | % |   |
| Non-Investment Grade            | ** ** |     | **18**     | ** ** |       |   | 20 |   |   |

 

A portion of our total wholesale credit riskis related to transactions that are recorded in our Consolidated BalanceSheets. These transactions primarily consist of open positions from ourwholesale marketing, risk management, and trading operation that are accountedfor using mark-to-market accounting, as well as amounts owed by wholesalecounterparties for transactions that settled but have not yet been paid. Thefollowing table highlights the credit quality and exposures related to theseactivities:
| **Rating**                                  | ** ** | **Total  Exposure  Before  Credit  Collateral** | ** ** | **Credit  Collateral** | ** ** | **Net  Exposure** | ** ** | **Number of  Counterparties  Greater  than 10%  of Net  Exposure** | ** ** | **Net  Exposure of  Counterparties  Greater than  10% of Net  Exposure** | ** ** |
|---------------------------------------------|------------|-------------------------------------------------|------------|------------------------|------------|-------------------|------------|-----------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------|------------|
| ** **                                  | ** ** | ***(Dollars in millions)***           | ** ** |
| Investment grade                            |       |                                            | $          | 1,268                  |       |              |       | $                                                                                 | 130        |                                                                                         |       |   | $ | 1,138 |   |   |   | — |   |   |   | $ | — |   |   |
| Split rating                                |       |                                            | 34         |                   |       |              | 5          |                                                                              |       |                                                                                         | 29         |   |   |   | — |   |   |   | — |   |   |
| Non-investment grade                        |       |                                            | 81         |                   |       |              | 44         |                                                                              |       |                                                                                         | 37         |   |   |   | — |   |   |   | — |   |   |
| Internally rated—investment  grade     |       |                                            | 511        |                   |       |              | 71         |                                                                              |       |                                                                                         | 440        |   |   |   | — |   |   |   | — |   |   |
| Internally rated—non-investment  grade |       |                                            | 229        |                   |       |              | 55         |                                                                              |       |                                                                                         | 174        |   |   |   | — |   |   |   | — |   |   |
| Total                                       |       |                                            | $          | 2,123                  |       |              |       | $                                                                                 | 305        |                                                                                         |       |   | $ | 1,818 |   |   |   | — |   |   |   | $ | — |   |   |

 

Due to thepossibility of extreme volatility in the prices of energy commodities andderivatives, the market value of contractual positions with individualcounterparties could exceed established credit limits or collateral provided bythose counterparties. If such a counterparty were then to fail to perform itsobligations under its contract (for example, fail to deliver the electricityour wholesale marketing, risk management, and trading operation had contractedfor), we could incur a loss that could have a material impact on our financialresults.

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

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***Retail CreditRisk***

We are exposedto retail credit risk through our competitive electricity and natural gassupply activities which serve commercial and industrial companies. Retailcredit risk results when customers default on their contractual obligations.This risk represents the loss that may be incurred due to the nonpayment of acustomer’s accounts receivable balance, as well as the loss from the resale ofenergy previously committed to serve the customer.

Retail creditrisk is managed through established credit policies, monitoring customerexposures, and the use of credit mitigation measures such as letters of creditor prepayment arrangements.

Our retail credit portfolio is well diversified with no significantcompany or industry concentrations. During 2006, we did not experience amaterial change in the credit quality of our retail credit portfolio comparedto 2005. Retail credit quality is dependent on the economy and the ability ofour customers to manage through unfavorable economic cycles and other marketchanges. If the business environment were to be negatively affected by changesin economic or other market conditions, our retail credit risk may be adverselyimpacted.

**Foreign Currency Risk**

Our merchant energy business is exposed to the impact of foreignexchange rate fluctuations. This foreign currency risk arises from ouractivities in countries where we transact in currencies other than the U.S.dollar. In 2006, our exposure to foreign currency risk was not material.However, we expect our foreign currency exposure to grow due to our Canadianoperations, global power, coal, freight, and natural gas operations, and ourUniStar venture. We manage our exposure to foreign currency exchange rate riskusing a comprehensive foreign currency hedging program. While we cannot predictcurrency fluctuations, the impact of foreign currency exchange rate risk couldbe material.

**Equity Price Risk**

We are exposedto price fluctuations in equity markets primarily through our pension planassets, our nuclear decommissioning trust funds, and trust assets securingcertain executive benefits. We are required by the NRC to maintain externallyfunded trusts for the costs of decommissioning our nuclear power plants. Wediscuss our nuclear decommissioning trust funds in more detail in *Note 1*.

A hypothetical 10% decrease in equity prices would result in anapproximate $130 million reduction in the fair value of our financialinvestments that are classified as trading or available-for-sale securities. In2006, our actual return on pension plan assets was $141.1 million due toadvances in the markets in which plan assets are invested. We describe ourfinancial investments in more detail in *Note 4*,and our pension plans in *Note 7*.

 

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**Item 7A.Quantitative and Qualitative Disclosures about Market Risk**

The informationrequired by this item with respect to market risk is set forth in *Item 7* of Part II of this Form 10-Kunder the heading *Market Risk*.

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**Item 8. Financial Statements and SupplementaryData**

REPORT OFMANAGEMENT

***FinancialStatements***

The managementof Constellation Energy Group, Inc. and Baltimore Gas and Electric Company(the “Companies”) is responsible for the information and representations in theCompanies’ financial statements. The Companies prepare the financial statementsin accordance with accounting principles generally accepted in the UnitedStates of America based upon available facts and circumstances and management’sbest estimates and judgments of known conditions.

PricewaterhouseCoopersLLP, an independent registered public accounting firm, has audited thefinancial statements and expressed their opinion on them. They performed theiraudit in accordance with the standards of the Public Company AccountingOversight Board (United States).

The Audit Committee of the Board of Directors, which consists of threeindependent Directors, meets periodically with management, internal auditors,and PricewaterhouseCoopers LLP to review the activities of each in dischargingtheir responsibilities. The internal audit staff and PricewaterhouseCoopers LLPhave free access to the Audit Committee.

***Management’sReport on Internal Control Over Financial Reporting***

The managementof Constellation Energy Group, Inc. (“Constellation Energy”), under thedirection of its principal executive officer and principal financial officer,is responsible for establishing and maintaining adequate internal control overfinancial reporting as defined in Exchange Act Rule 13a-15(f).

ConstellationEnergy’s system of internal control over financial reporting is designed toprovide reasonable assurance to Constellation Energy’s management and Board ofDirectors regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generallyaccepted accounting principles in the United States of America.

The managementof Constellation Energy conducted an evaluation of the effectiveness ofConstellation Energy’s internal control over financial reporting using theframework in Internal Control—Integrated Framework issued by the Committee ofSponsoring Organizations of the Treadway Commission (COSO). As noted in theCOSO framework, an internal control system, no matter how well conceived andoperated, can provide only reasonable-not absolute-assurance tomanagement and the Board of Directors regarding achievement of an entity’sfinancial reporting objectives. Based upon the evaluation under this framework,management concluded that Constellation Energy’s internal control overfinancial reporting was effective as of December 31, 2006.

PricewaterhouseCoopersLLP, an independent registered public accounting firm, has audited management’sassessment of the effectiveness of Constellation Energy’s internal control overfinancial reporting at December 31, 2006, as stated in their report setforth below.

As discussed in *Item 9A. Controls and Procedures*, the management ofBaltimore Gas & Electric Company (“BGE”) has not assessed theeffectiveness of BGE’s internal control over financial reporting on astandalone basis because it is not yet required to do so by applicable federalsecurities laws and regulations.
|                                                                                          |   |                                                                                                            |
|------------------------------------------------------------------------------------------|--------|------------------------------------------------------------------------------------------------------------|
| Mayo A. Shattuck III*Chairman of the Board, President and Chief  Executive Officer* |   | E. Follin Smith*Executive Vice-President, Chief Financial Officer, and Chief  Administrative Officer* |

 

REPORTS OFINDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

*To the Board of Directors and Shareholders ofConstellation Energy Group, Inc.*

We have completed integrated audits of Constellation Energy Group, Inc.and Subsidiaries’ consolidated financial statements and of its internal controlover financial reporting as of December 31, 2006 in accordance with thestandards of the Public Company Accounting Oversight Board (United States). Ouropinions, based on our audits, are presented below.

**Consolidatedfinancial statements and financial statement schedule**

In our opinion,the consolidated financial statements listed in the index appearing under Item15(a) (1) present fairly, in all material respects, the financialposition of Constellation Energy Group, Inc. and Subsidiaries (theCompany) at December 31, 2006 and 2005, and the results of theiroperations and their cash flows for each of the three years in the period ended

December 31,2006 in conformity with accounting principles generally accepted in the UnitedStates of America. In addition, in our opinion, the financial statementschedule listed in the index appearing under Item 15(a) (2) presentsfairly, in all material respects, the information set forth therein when readin conjunction with the related consolidated financial statements. Thesefinancial statements and financial statement schedule are the responsibility ofthe Company’s management. Our responsibility is to express an opinion on thesefinancial statements and financial statement schedule based on our audits. Weconducted our audits of these statements in accordance with the standards ofthe Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance aboutwhether the financial statements are free of material misstatement. An audit offinancial statements includes examining, on a test basis, evidence supportingthe 

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amounts anddisclosures in the financial statements, assessing the accounting principlesused and significant estimates made by management, and evaluating the overallfinancial statement presentation. We believe that our audits provide areasonable basis for our opinion.

As discussed in*Note 1* to the consolidated financialstatements, in 2006 the Company changed its method of accounting for definedbenefit pension and other postretirement plans. As discussed in *Note 1*to the consolidated financial statements, in 2005 the Company changed itsmethod of accounting forconditional asset retirement obligations and the accounting for stock basedcompensation.

We have also previously audited, in accordance with the standards ofthe Public Company Accounting Oversight Board (United States), the consolidatedbalance sheets and statements of capitalization of Constellation Energy Group, Inc.and Subsidiaries as of December 31, 2004, 2003, and 2002, and the relatedconsolidated statements of income, cash flows, and common shareholders’ equityand comprehensive income for the years ended December 31, 2003 and 2002(none of which are presented herein); and we expressed unqualified opinions onthose consolidated financial statements. In our opinion, the information setforth in the Summary of Operations and Summary of Financial Condition ofConstellation Energy Group, Inc. and Subsidiaries included in the SelectedFinancial Data for each of the five years in the period ended December 31,2006, is fairly stated, in all material respects, in relation to theconsolidated financial statements from which it has been derived.

**Internal controlover financial reporting**

Also, in ouropinion, management’s assessment, included in Management’s Report on InternalControl Over Financial Reporting appearing under Item 8, that the Companymaintained effective internal control over financial reporting as of December 31,2006, based on criteria established in *InternalControl—Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO), is fairly stated, in allmaterial respects, based on those criteria. Furthermore, in our opinion, theCompany maintained, in all material respects, effective internal control overfinancial reporting as of December 31, 2006, based on criteria establishedin *Internal Control—Integrated Framework*issued by the COSO. The Company’s management is responsible for maintainingeffective internal control over financial reporting and for its assessment ofthe effectiveness of internal control over financial reporting. Ourresponsibility is to express opinions on management’s assessment and on theeffectiveness of the Company’s internal control over financial reporting basedon our audit. We conducted our audit of internal control over financialreporting in accordance with the standards of the Public Company AccountingOversight Board (United States). Those standards require that we plan andperform the audit to obtain reasonable assurance about whether effectiveinternal control over financial reporting was maintained in all materialrespects. An audit of internal control over financial reporting includesobtaining an understanding of internal control over financial reporting,evaluating management’s assessment, testing and evaluating the design andoperating effectiveness of internal control, and performing such otherprocedures as we consider necessary in the circumstances. We believe that ouraudit provides a reasonable basis for our opinions.

A company’sinternal control over financial reporting is a process designed to providereasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance withgenerally accepted accounting principles. A company’s internal control overfinancial reporting includes those policies and procedures that (i) pertainto the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (ii) providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally acceptedaccounting principles, and that receipts and expenditures of the company arebeing made only in accordance with authorizations of management and directorsof the company; and (iii) provide reasonable assurance regardingprevention or timely detection of unauthorized acquisition, use, or dispositionof the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financialreporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk thatcontrols may become inadequate because of changes in conditions, or that thedegree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLPBaltimore, MarylandFebruary 26, 2007

*To Board of Directors and Shareholder of Baltimore Gas and ElectricCompany*

In our opinion,the consolidated financial statements listed in the index appearing under Item15(a) (1) present fairly, in all material respects, the financialposition of Baltimore Gas and Electric Company and Subsidiaries (the Company)at December 31, 2006 and 2005, and the results of their operations andtheir cash flows for each of the three years in the period ended December 31,2006 in conformity with accounting principles generally accepted in the UnitedStates of America. In addition, in our opinion, the financial statementschedule listed in the index appearing under Item 15(a) (2) presentsfairly, in all material respects, the information set forth therein when readin conjunction with the related consolidated financial statements. Thesefinancial statements and financial statement schedule are the responsibility ofthe Company’s management. Our responsibility is to express an opinion on thesefinancial statements and financial statement schedule based on our audits. Weconducted our audits of these statements in accordance with the standards ofthe Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance aboutwhether the financial statements are free of material misstatement. An auditincludes examining, on a test basis, evidence supporting the amounts anddisclosures in the 

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financialstatements, assessing the accounting principles used and significant estimatesmade by management, and evaluating the overall financial statementpresentation. We believe that our audits provide a reasonable basis for ouropinion.

We have also previously audited, in accordance with the standards ofthe Public Company Accounting Oversight Board (United States), the consolidatedbalance sheets of Baltimore Gas and Electric Company and Subsidiaries as of December 31,2004, 2003 and 2002, and the related consolidated statements of income, cashflows, and comprehensive income for the years ended December 31, 2003 and2002 (none of which are presented herein); and we expressed unqualifiedopinions on those consolidated financial statements. In our opinion, theinformation set forth in the Summary of Operations and Summary of FinancialCondition of Baltimore Gas and Electric Company and Subsidiaries included inthe Selected Financial Data for each of the five years in the period ended December 31,2006, is fairly stated, in all material respects, in relation to theconsolidated financial statements from which it has been derived.

PricewaterhouseCoopersLLPBaltimore, MarylandFebruary 26, 2007

 

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CONSOLIDATEDSTATEMENTS OF INCOME

***ConstellationEnergy Group, Inc. and Subsidiaries***
| ***Year Ended December 31,***                                                                                              | ** ** | **2006**                                                               | ** **   | **2005** | ** ** | **2004** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------|--------------|----------|------------|----------|------------|
| ** **                                                                                                                                | ** ** | ***(In millions, except per share amounts)*** | ** **   |
| **Revenues**                                                                                                                              | ** ** | ** **                                                             |         |     |       |     |       |
| Nonregulated revenues                                                                                                                     | ** ** | **$**                                                                  | **16,279.0** |     | $          | 13,970.1 |       | $ | 9,404.5 |   |
| Regulated electric revenues                                                                                                               | ** ** | **2,115.9**                                                            |         | 2,036.5  |       | 1,967.6  |       |
| Regulated gas revenues                                                                                                                    | ** ** | **890.0**                                                              |         | 961.7    |       | 755.1    |       |
| Total revenues                                                                                                                            | ** ** | **19,284.9**                                                           |         | 16,968.3 |       | 12,127.2 |       |
| **Expenses**                                                                                                                              | ** ** | ** **                                                             |         |     |       |     |       |
| Fuel and purchased energy  expenses                                                                                                       | ** ** | **14,930.7**                                                           |         | 13,239.6 |       | 8,693.2  |       |
| Operating expenses                                                                                                                        | ** ** | **2,165.8**                                                            |         | 1,900.7  |       | 1,714.0  |       |
| Workforce reduction costs                                                                                                                 | ** ** | **28.2**                                                               |         | 4.4      |       | 9.7      |       |
| Merger-related costs                                                                                                                      | ** ** | **18.3**                                                               |         | 17.0     |       | —   |       |
| Depreciation, depletion, and  amortization                                                                                                | ** ** | **523.9**                                                              |         | 523.0    |       | 488.4    |       |
| Accretion of asset retirement  obligations                                                                                                | ** ** | **67.6**                                                               |         | 62.0     |       | 53.1     |       |
| Taxes other than income taxes                                                                                                             | ** ** | **290.7**                                                              |         | 277.1    |       | 250.7    |       |
| Total expenses                                                                                                                            | ** ** | **18,025.2**                                                           |         | 16,023.8 |       | 11,209.1 |       |
| **Gain on Sale of Gas-Fired Plants**                                                                                                      | ** ** | **73.8**                                                               |         | —   |       | —   |       |
| **Income from Operations**                                                                                                                | ** ** | **1,333.5**                                                            |         | 944.5    |       | 918.1    |       |
| **Gain on Initial Public Offering of CEP LLC**                                                                                            | ** ** | **28.7**                                                               |         | —   |       | —   |       |
| **Other Income**                                                                                                                          | ** ** | **66.1**                                                               |         | 65.5     |       | 25.5     |       |
| **Fixed Charges**                                                                                                                         | ** ** | ** **                                                             |         |     |       |     |       |
| Interest expense                                                                                                                          | ** ** | **329.2**                                                              |         | 306.9    |       | 324.4    |       |
| Interest capitalized and  allowance for borrowed funds used during construction                                                           | ** ** | **(13.7**                                                              | **)**        | (9.9     | )          | (10.8    | )          |
| BGE preference stock dividends                                                                                                            | ** ** | **13.2**                                                               |         | 13.2     |       | 13.2     |       |
| Total fixed charges                                                                                                                       | ** ** | **328.7**                                                              |         | 310.2    |       | 326.8    |       |
| **Income from Continuing Operations Before Income Taxes**                                                                                 | ** ** | **1,099.6**                                                            |         | 699.8    |       | 616.8    |       |
| **Income Tax Expense**                                                                                                                    | ** ** | **351.0**                                                              |         | 163.9    |       | 118.4    |       |
| **Income from Continuing Operations and Before Cumulative Effects of  Changes in Accounting Principles**                                  | ** ** | **748.6**                                                              |         | 535.9    |       | 498.4    |       |
| Income from discontinued  operations, net of income taxes of $107.7, $61.6, $27.3, respectively                                           | ** ** | **187.8**                                                              |         | 94.4     |       | 41.3     |       |
| Cumulative effects of changes in  accounting principles, net of income taxes of $(4.7)                                                    | ** ** | **—**                                                             |         | (7.2     | )          | —   |       |
| **Net Income**                                                                                                                            | ** ** | **$**                                                                  | **936.4**    |     | $          | 623.1    |       | $ | 539.7 |   |
| **Earnings Applicable to Common Stock**                                                                                                   | ** ** | **$**                                                                  | **936.4**    |     | $          | 623.1    |       | $ | 539.7 |   |
| **Average Shares of Common Stock Outstanding—Basic**                                                                                 | ** ** | **179.4**                                                              |         | 177.5    |       | 172.1    |       |
| **Average Shares of Common Stock Outstanding—Diluted**                                                                               | ** ** | **181.4**                                                              |         | 179.7    |       | 173.1    |       |
| **Earnings Per Common Share from Continuing  Operations and Before Cumulative Effects of Changes in Accounting  Principles—Basic**   | ** ** | **$**                                                                  | **4.17**     |     | $          | 3.02     |       | $ | 2.90 |   |
| Income from discontinued  operations                                                                                                      | ** ** | **1.05**                                                               |         | 0.53     |       | 0.24     |       |
| Cumulative effects of changes in  accounting principles                                                                                   |       | —                                                                 |         | (0.04    | )          | —   |       |
| **Earnings Per Common Share—Basic**                                                                                                  | ** ** | **$**                                                                  | **5.22**     |     | $          | 3.51     |       | $ | 3.14 |   |
| **Earnings Per Common Share from Continuing  Operations and Before Cumulative Effects of Changes in Accounting  Principles—Diluted** | ** ** | **$**                                                                  | **4.12**     |     | $          | 2.98     |       | $ | 2.88 |   |
| Income from discontinued  operations                                                                                                      | ** ** | **1.04**                                                               |         | 0.53     |       | 0.24     |       |
| Cumulative effects of changes in  accounting principles                                                                                   |       | —                                                                 |         | (0.04    | )          | —   |       |
| **Earnings Per Common Share—Diluted**                                                                                                | ** ** | **$**                                                                  | **5.16**     |     | $          | 3.47     |       | $ | 3.12 |   |
| **Dividends  Declared Per Common Share**                                                                                                  | ** ** | **$**                                                                  | **1.51**     |     | $          | 1.34     |       | $ | 1.14 |   |

 

*See Notes to Consolidated Financial Statements.*

*Certain prior-year amounts have been reclassifiedto conform with the current year’s presentation.*

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CONSOLIDATEDBALANCE SHEETS

***Constellation EnergyGroup, Inc. and Subsidiaries***
| ***At December 31,***                                                                  | ** ** | **2006**                 | ** **   | **2005**   | ** ** |
|--------------------------------------------------------------------------------------------------|------------|--------------------------|--------------|------------|------------|
| ** **                                                                                       | ** ** | ***(In millions)*** | ** **   |
| Assets                                                                                           |       |                     |         |       |       |
| **Current  Assets**                                                                              | ** ** | ** **               | ** **   | ** ** | ** ** |
| Cash and  cash equivalents                                                                       | ** ** | **$**                    | **2,289.1**  |       | $          | 813.0 |   |
| Accounts  receivable (net of allowance for uncollectibles of **$48.9**  and $47.4, respectively) | ** ** | **3,248.3**              |         | 2,727.9    |       |
| Fuel stocks                                                                                      | ** ** | **599.5**                |         | 489.5      |       |
| Materials  and supplies                                                                          | ** ** | **200.2**                |         | 197.0      |       |
| Mark-to-market  energy assets                                                                    | ** ** | **1,294.8**              |         | 1,339.2    |       |
| Risk  management assets                                                                          | ** ** | **261.7**                |         | 1,244.3    |       |
| Unamortized  energy contract assets                                                              | ** ** | **35.2**                 |         | 55.6       |       |
| Deferred  income taxes                                                                           | ** ** | **674.3**                |         | —     |       |
| Other                                                                                            | ** ** | **497.0**                |         | 555.3      |       |
| Total  current assets                                                                            | ** ** | **9,100.1**              |         | 7,421.8    |       |
| **Investments  and Other Assets**                                                                | ** ** | ** **               |         |       |       |
| Nuclear  decommissioning trust funds                                                             | ** ** | **1,240.1**              |         | 1,110.7    |       |
| Investments  in qualifying facilities and power projects                                         | ** ** | **308.6**                |         | 306.2      |       |
| Regulatory  assets (net)                                                                         | ** ** | **389.0**                |         | 154.3      |       |
| Goodwill                                                                                         | ** ** | **157.6**                |         | 147.1      |       |
| Mark-to-market  energy assets                                                                    | ** ** | **623.4**                |         | 1,089.3    |       |
| Risk  management assets                                                                          | ** ** | **325.7**                |         | 626.0      |       |
| Unamortized  energy contract assets                                                              | ** ** | **123.6**                |         | 141.2      |       |
| Other                                                                                            | ** ** | **311.4**                |         | 410.6      |       |
| Total  investments and other assets                                                              | ** ** | **3,479.4**              |         | 3,985.4    |       |
| **Property,  Plant and Equipment**                                                               | ** ** | ** **               |         |       |       |
| Nonregulated  property, plant and equipment                                                      | ** ** | **7,587.6**              |         | 8,580.8    |       |
| Regulated  property, plant and equipment                                                         | ** ** | **5,752.9**              |         | 5,520.5    |       |
| Nuclear fuel  (net of amortization)                                                              | ** ** | **339.9**                |         | 302.0      |       |
| Accumulated  depreciation                                                                        | ** ** | **(4,458.3**             | **)**        | (4,336.6   | )          |
| Net  property, plant and equipment                                                               | ** ** | **9,222.1**              |         | 10,066.7   |       |
| **Total Assets**                                                                                 | ** ** | **$**                    | **21,801.6** |       | $          | 21,473.9 |   |

 

*See Notes to Consolidated FinancialStatements.*

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CONSOLIDATED BALANCE SHEETS

***ConstellationEnergy Group, Inc. and Subsidiaries***
| ***At December 31,***                                     | ** ** | **2006**                 | ** **   | **2005**   | ** ** |
|---------------------------------------------------------------------|------------|--------------------------|--------------|------------|------------|
| ** **                                                          | ** ** | ***(In millions)*** | ** **   |
| Liabilities and Equity                                              |       |                     |         |       |       |
| **Current Liabilities**                                             |       |                     |         |       |       |
| Short-term borrowings                                               | ** ** | **$**                    | **—**   |       | $          | 0.7 |   |
| Current portion of long-term debt                                   | ** ** | **878.8**                |         | 491.3      |       |
| Accounts payable and accrued liabilities                            | ** ** | **2,137.2**              |         | 1,667.9    |       |
| Customer deposits and collateral                                    | ** ** | **347.2**                |         | 458.9      |       |
| Mark-to-market energy liabilities                                   | ** ** | **1,071.7**              |         | 1,348.7    |       |
| Risk management liabilities                                         | ** ** | **1,340.0**              |         | 483.5      |       |
| Unamortized energy contract liabilities                             | ** ** | **378.3**                |         | 489.5      |       |
| Deferred income taxes                                               |       | —                   |         | 151.4      |       |
| Accrued expenses and other                                          | ** ** | **969.5**                |         | 780.4      |       |
| Total current liabilities                                           | ** ** | **7,122.7**              |         | 5,872.3    |       |
| **Deferred Credits and Other Liabilities**                          |       |                     |         |       |       |
| Deferred income taxes                                               | ** ** | **1,435.8**              |         | 1,180.8    |       |
| Asset retirement obligations                                        | ** ** | **974.8**                |         | 908.0      |       |
| Mark-to-market energy liabilities                                   | ** ** | **392.4**                |         | 912.3      |       |
| Risk management liabilities                                         | ** ** | **707.3**                |         | 1,035.5    |       |
| Unamortized energy contract liabilities                             | ** ** | **958.0**                |         | 1,118.7    |       |
| Defined benefit obligations                                         | ** ** | **928.3**                |         | 784.0      |       |
| Deferred investment tax credits                                     | ** ** | **57.2**                 |         | 64.1       |       |
| Other                                                               | ** ** | **109.0**                |         | 101.0      |       |
| Total deferred credits and other liabilities                        | ** ** | **5,562.8**              |         | 6,104.4    |       |
| **Capitalization (See Consolidated Statements of  Capitalization)** |       |                     |         |       |       |
| Long-term debt                                                      | ** ** | **4,222.3**              |         | 4,369.3    |       |
| Minority interests                                                  | ** ** | **94.5**                 |         | 22.4       |       |
| BGE preference stock not subject to mandatory  redemption           | ** ** | **190.0**                |         | 190.0      |       |
| Common shareholders’ equity                                    | ** ** | **4,609.3**              |         | 4,915.5    |       |
| Total capitalization                                                | ** ** | **9,116.1**              |         | 9,497.2    |       |
| **Commitments, Guarantees, and Contingencies (see Note 12)**        | ** ** | ** **               | ** **   | ** ** | ** ** |
| **Total  Liabilities and Equity**                                   | ** ** | **$**                    | **21,801.6** |       | $          | 21,473.9 |   |

 

*See Notesto Consolidated Financial Statements.*

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CONSOLIDATED STATEMENTS OF CASH FLOWS

***ConstellationEnergy Group, Inc. and Subsidiaries***
| ***Year Ended December 31,***                                                                                                           | ** ** | **2006**                 | ** **  | **2005** | ** ** | **2004** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------|-------------|----------|------------|----------|------------|
| ** **                                                                                                                                             | ** ** | ***(In millions)*** | ** **  |
| **Cash Flows From Operating Activities**                                                                                                               |       |                     |        |     |       |     |       |
| Net income                                                                                                                                             | ** ** | **$**                    | **936.4**   |     | $          | 623.1    |       | $ | 539.7 |   |
| Adjustments to reconcile to net  cash provided by operating activities (Gain) loss on sales of  gas-fired plants and discontinued operations |       | **(191.4**               | )           | (13.8    | )          | 50.1     |       |
| Cumulative effects of changes in  accounting principles                                                                                                |       | —                   |        | 7.2      |       | —   |       |
| Depreciation, depletion, and  amortization                                                                                                             | ** ** | **545.1**                |        | 606.5    |       | 650.3    |       |
| Accretion of asset retirement  obligations                                                                                                             | ** ** | **67.6**                 |        | 62.1     |       | 53.2     |       |
| Deferred income taxes                                                                                                                                  | ** ** | **128.0**                |        | 136.9    |       | 123.4    |       |
| Investment tax credit  adjustments                                                                                                                     | ** ** | **(6.9**                 | )           | (7.1     | )          | (7.2     | )          |
| Deferred fuel costs                                                                                                                                    | ** ** | **(348.5**               | )           | (11.9    | )          | 6.0      |       |
| Defined benefit obligation  expense                                                                                                                    | ** ** | **129.7**                |        | 94.2     |       | 81.1     |       |
| Defined benefit obligation  payments                                                                                                                   | ** ** | **(89.2**                | )           | (90.8    | )          | (94.7    | )          |
| Gain on initial public offering  of CEP LLC                                                                                                            | ** ** | **(28.7**                | )           | —   |       | —   |       |
| Equity in earnings of affiliates  less than dividends received                                                                                         | ** ** | **27.6**                 |        | 38.7     |       | 29.5     |       |
| Proceeds from derivative power  sales contracts classified as financing activities under  SFAS No. 149                                       | ** ** | **2.6**                  |        | (72.6    | )          | —   |       |
| Changes in                                                                                                                                             |       |                     |        |     |       |     |       |
| Accounts receivable                                                                                                                                    | ** ** | **(653.7**               | )           | (961.2   | )          | (397.4   | )          |
| Mark-to-market  energy assets and liabilities                                                                                                          | ** ** | **(275.9**               | )           | (88.4    | )          | (27.2    | )          |
| Risk management assets and  liabilities                                                                                                                | ** ** | **(4.4**                 | )           | (27.5    | )          | (39.7    | )          |
| Materials, supplies, and fuel  stocks                                                                                                                  | ** ** | **(267.2**               | )           | (250.3   | )          | (112.1   | )          |
| Other current assets                                                                                                                                   | ** ** | **240.6**                |        | (277.1   | )          | 5.3      |       |
| Accounts payable and accrued  liabilities                                                                                                              | ** ** | **380.5**                |        | 282.8    |       | 260.2    |       |
| Other current liabilities                                                                                                                              | ** ** | **(91.8**                | )           | 546.4    |       | (8.7     | )          |
| Other                                                                                                                                                  | ** ** | **24.9**                 |        | 30.0     |       | (25.0    | )          |
| Net cash provided by operating  activities                                                                                                             | ** ** | **525.3**                |        | 627.2    |       | 1,086.8  |       |
| **Cash Flows From Investing Activities**                                                                                                               |       |                     |        |     |       |     |       |
| Investments in property, plant  and equipment                                                                                                          | ** ** | **(962.9**               | )           | (760.0   | )          | (703.6   | )          |
| Asset acquisitions and business  combinations, net of cash acquired                                                                                    | ** ** | **(137.6**               | )           | (237.2   | )          | (457.3   | )          |
| Investments in nuclear  decommissioning trust fund securities                                                                                          | ** ** | **(394.6**               | )           | (370.8   | )          | (424.2   | )          |
| Proceeds from nuclear  decommissioning trust fund securities                                                                                           | ** ** | **385.8**                |        | 353.2    |       | 402.2    |       |
| Net proceeds from sale of  gas-fired plants and discontinued operations                                                                                | ** ** | **1,630.7**              |        | 289.4    |       | 72.7     |       |
| Issuances of loans receivable                                                                                                                          | ** ** | **(65.4**                | )           | (82.8    | )          | —   |       |
| Sale of investments and other  assets                                                                                                                  | ** ** | **43.9**                 |        | 14.4     |       | 36.1     |       |
| Contract and portfolio  acquisitions                                                                                                                   | ** ** | **(2.3**                 | )           | (336.2   | )          | —   |       |
| Other investments                                                                                                                                      | ** ** | **62.5**                 |        | (44.0    | )          | (78.6    | )          |
| Net cash provided by (used in)  investing activities                                                                                                   | ** ** | **560.1**                |        | (1,174.0 | )          | (1,152.7 | )          |
| **Cash Flows From Financing Activities**                                                                                                               |       |                     |        |     |       |     |       |
| Net (maturity) issuance of short-term  borrowings                                                                                                      | ** ** | **(0.7**                 | )           | 10.7     |       | (9.6     | )          |
| Proceeds from issuance of                                                                                                                              |       |                     |        |     |       |     |       |
| Common stock                                                                                                                                           | ** ** | **84.4**                 |        | 96.9     |       | 293.9    |       |
| Long-term debt                                                                                                                                         | ** ** | **852.0**                |        | 12.0     |       | 100.0    |       |
| Proceeds from initial public  offering of Constellation Energy Partners LLC                                                                            | ** ** | **101.3**                |        | —   |       | —   |       |
| Common stock dividends paid                                                                                                                            | ** ** | **(264.0**               | )           | (228.8   | )          | (189.7   | )          |
| Proceeds from contract and  portfolio acquisitions                                                                                                     | ** ** | **221.3**                |        | 1,026.9  |       | 117.5    |       |
| Repayment of long-term  debt                                                                                                                           | ** ** | **(609.1**               | )           | (362.3   | )          | (243.2   | )          |
| Proceeds from derivative power  sales contracts classified as financing activities under  SFAS No. 149                                       | ** ** | **(2.6**                 | )           | 72.6     |       | —   |       |
| Other                                                                                                                                                  | ** ** | **8.1**                  |        | 25.5     |       | (18.0    | )          |
| Net cash provided by financing  activities                                                                                                             | ** ** | **390.7**                |        | 653.5    |       | 50.9     |       |
| **Net Increase (Decrease) in Cash and Cash Equivalents**                                                                                               | ** ** | **1,476.1**              |        | 106.7    |       | (15.0    | )          |
| **Cash and Cash Equivalents at Beginning of Year**                                                                                                     | ** ** | **813.0**                |        | 706.3    |       | 721.3    |       |
| **Cash and Cash Equivalents at End of Year**                                                                                                           | ** ** | **$**                    | **2,289.1** |     | $          | 813.0    |       | $ | 706.3 |   |
| **Other Cash Flow Information:**                                                                                                                       |       |                     |        |     |       |     |       |
| Cash paid during the year for:                                                                                                                         |       |                     |        |     |       |     |       |
| Interest (net of amounts  capitalized)                                                                                                                 | ** ** | **$**                    | **304.7**   |     | $          | 301.3    |       | $ | 327.9 |   |
| Income taxes                                                                                                                                           | ** ** | **$**                    | **109.3**   |     | $          | 115.3    |       | $ | 203.9 |   |

 

*See Notes to Consolidated Financial Statements.*

*Certain prior-year amounts have beenreclassified to conform with the current year’s presentation.*

70

----

CONSOLIDATED STATEMENTS OFCOMMON SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

***Constellation EnergyGroup, Inc. and Subsidiaries***
| ** **                                                                                            | ** **   | **Common Stock**                                                                                     | ** **   | **Retained** | ** **  | **Accumulated  Other  Comprehensive** | ** ** | **Total**   | ** **   |
|-------------------------------------------------------------------------------------------------------|--------------|-----------------------------------------------------------------------------------------------------------|--------------|--------------|-------------|---------------------------------------|------------|-------------|--------------|
| ***Year Ended December 31, 2006, 2005, and 2004***                 | ** **   | **Shares**                                                                                                | ** **   | **Amount**   | ** **  | **Earnings**                          | ** ** | **Loss**    | ** **   | **Amount** | ** ** |
| *** ***                                                                                          | *** *** | ***(Dollar amounts in millions, number of shares in thousands)*** | *** *** |
| **Balance at December 31, 2003**                                                                 |         | 167,819                                                                                                   |         | $            | 2,179.8     |                                  | $          | 2,081.9     |         |   | $ | (121.2 | ) |   | $ | 4,140.5 |   |
| Comprehensive Income                                                                                  |         |                                                                                                      |         |         |        |                                  |       |        |         |   |   |   |   |
| Net income                                                                                            |         |                                                                                                      |         |         |        | 539.7                                 |       |        |         |   |   | 539.7 |   |
| Other comprehensive income                                                                            |         |                                                                                                      |         |         |        |                                  |       |        |         |   |   |   |   |
| Hedging instruments:                                                                                  |         |                                                                                                      |         |         |        |                                  |       |        |         |   |   |   |   |
| Reclassification of net gains on hedging instruments from OCI to net  income, net of taxes of $169.0  |         |                                                                                                      |         |         |        |                                  |       |        | (270.8       | ) |   | (270.8 | ) |
| Net unrealized gain on hedging instruments, net of taxes of $124.7                                    |         |                                                                                                      |         |         |        |                                  |       |        | 196.8        |   |   | 196.8 |   |
| Available-for-sale securities:                                                                        |         |                                                                                                      |         |         |        |                                  |       |        |         |   |   |   |   |
| Reclassification of net loss on securities from OCI to net income,  net of taxes of $1.4              |         |                                                                                                      |         |         |        |                                  |       |        | 2.2          |   |   | 2.2 |   |
| Net unrealized gain on securities, net of taxes of $22.2                                              |         |                                                                                                      |         |         |        |                                  |       |        | 33.7         |   |   | 33.7 |   |
| Minimum pension liability, net of taxes of $27.9                                                      |         |                                                                                                      |         |         |        |                                  |       |        | (42.6        | ) |   | (42.6 | ) |
| Net unrealized gain on foreign currency translation                                                   |         |                                                                                                      |         |         |        |                                  |       |        | 0.4          |   |   | 0.4 |   |
| Total Comprehensive Income                                                                            |         |                                                                                                      |         |         |        | 539.7                                 |       |        | (80.3        | ) |   | 459.4 |   |
| Common stock dividend declared ($1.14 per share)                                                      |         |                                                                                                      |         |         |        | (196.3                                | )          |        |         |   |   | (196.3 | ) |
| Common stock issued                                                                                   |         | 8,514                                                                                                     |         | 322.7        |        |                                  |       |        |         |   |   | 322.7 |   |
| Other                                                                                                 |         |                                                                                                      |         |         |        | 0.6                                   |       |        |         |   |   | 0.6 |   |
| **Balance  at December 31, 2004**                                                                |         | 176,333                                                                                                   |         | 2,502.5      |        | 2,425.9                               |       |        | (201.5       | ) |   | 4,726.9 |   |
| Comprehensive Income                                                                                  |         |                                                                                                      |         |         |        |                                  |       |        |         |   |   |   |   |
| Net income                                                                                            |         |                                                                                                      |         |         |        | 623.1                                 |       |        |         |   |   | 623.1 |   |
| Other comprehensive income                                                                            |         |                                                                                                      |         |         |        |                                  |       |        |         |   |   |   |   |
| Hedging instruments:                                                                                  |         |                                                                                                      |         |         |        |                                  |       |        |         |   |   |   |   |
| Reclassification of net gains on hedging instruments from OCI to net  income, net of taxes of $492.2  |         |                                                                                                      |         |         |        |                                  |       |        | (794.6       | ) |   | (794.6 | ) |
| Net unrealized gain on hedging instruments, net of taxes of $335.9                                    |         |                                                                                                      |         |         |        |                                  |       |        | 534.7        |   |   | 534.7 |   |
| Available-for-sale securities:                                                                        |         |                                                                                                      |         |         |        |                                  |       |        |         |   |   |   |   |
| Reclassification of net gains on securities from OCI to net income,  net of taxes of $1.2             |         |                                                                                                      |         |         |        |                                  |       |        | (1.8         | ) |   | (1.8 | ) |
| Net unrealized gain on securities, net of taxes of $15.7                                              |         |                                                                                                      |         |         |        |                                  |       |        | 23.8         |   |   | 23.8 |   |
| Minimum pension liability, net of taxes of $50.4                                                      |         |                                                                                                      |         |         |        |                                  |       |        | (77.1        | ) |   | (77.1 | ) |
| Net unrealized gain on foreign currency translation                                                   |         |                                                                                                      |         |         |        |                                  |       |        | 1.0          |   |   | 1.0 |   |
| Total Comprehensive Income                                                                            |         |                                                                                                      |         |         |        | 623.1                                 |       |        | (314.0       | ) |   | 309.1 |   |
| Common stock dividend declared ($1.34 per share)                                                      |         |                                                                                                      |         |         |        | (238.4                                | )          |        |         |   |   | (238.4 | ) |
| Common stock issued                                                                                   |         | 1,968                                                                                                     |         | 118.3        |        |                                  |       |        |         |   |   | 118.3 |   |
| Other                                                                                                 |         |                                                                                                      |         |         |        | (0.4                                  | )          |        |         |   |   | (0.4 | ) |
| **Balance  at December 31, 2005**                                                                |         | 178,301                                                                                                   |         | 2,620.8      |        | 2,810.2                               |       |        | (515.5       | ) |   | 4,915.5 |   |
| Comprehensive Income                                                                                  | ** **   | ** **                                                                                                | ** **   | ** **   | ** **  | ** **                            | ** ** | ** **  | ** **   |   | ** ** | ** ** | ** ** |
| Net income                                                                                            | ** **   | ** **                                                                                                | ** **   | ** **   | ** **  | **936.4**                             | ** ** | ** **  | ** **   |   | ** ** | **936.4** | ** ** |
| Other comprehensive income                                                                            |         |                                                                                                      |         |         |        |                                  |       |        |         |   |   |   |   |
| Hedging instruments:                                                                                  |         |                                                                                                      |         |         |        |                                  |       |        |         |   |   |   |   |
| Reclassification of net losses on hedging instruments from OCI to net  income, net of taxes of $375.6 | ** **   | ** **                                                                                                | ** **   | ** **   | ** **  | ** **                            | ** ** | ** **  | **620.8**    |   | ** ** | **620.8** | ** ** |
| Net unrealized loss on hedging instruments, net of taxes of $1,025.8                                  | ** **   | ** **                                                                                                | ** **   | ** **   | ** **  | ** **                            | ** ** | ** **  | **(1,683.4** | ) | ** ** | **(1,683.4** | **)** |
| Available-for-sale securities:                                                                        |         |                                                                                                      |         |         |        |                                  |       |        |         |   |   |   |   |
| Reclassification of net gains on securities from OCI to net income,  net of taxes of $0.1             | ** **   | ** **                                                                                                | ** **   | ** **   | ** **  | ** **                            | ** ** | ** **  | **(0.2**     | ) | ** ** | **(0.2** | **)** |
| Net unrealized gain on securities, net of taxes of $45.5                                              | ** **   | ** **                                                                                                | ** **   | ** **   | ** **  | ** **                            | ** ** | ** **  | **69.7**     |   | ** ** | **69.7** | ** ** |
| Minimum pension liability, net of taxes of $49.6                                                      | ** **   | ** **                                                                                                | ** **   | ** **   | ** **  | ** **                            | ** ** | ** **  | **75.6**     |   | ** ** | **75.6** | ** ** |
| Net unrealized loss on foreign currency translation                                                   | ** **   | ** **                                                                                                | ** **   | ** **   | ** **  | ** **                            | ** ** | ** **  | **(1.1**     | ) | ** ** | **(1.1** | **)** |
| Total Comprehensive Income                                                                            | ** **   | ** **                                                                                                | ** **   | ** **   | ** **  | **936.4**                             | ** ** | ** **  | **(918.6**   | ) | ** ** | **17.8** | ** ** |
| Effect of adoption of SFAS No. 158, net of taxes of $111.3                                       | ** **   | ** **                                                                                                | ** **   | ** **   | ** **  | ** **                            | ** ** | ** **  | **(169.5**   | ) | ** ** | **(169.5** | **)** |
| Common stock dividend declared ($1.51 per share)                                                      | ** **   | ** **                                                                                                | ** **   | ** **   | ** **  | **(272.6**                            | **)**      | ** **  | ** **   |   | ** ** | **(272.6** | **)** |
| Common stock issued                                                                                   | ** **   | **2,218**                                                                                                 | ** **   | **117.8**    | ** **  | ** **                            | ** ** | ** **  | ** **   |   | ** ** | **117.8** | ** ** |
| Other                                                                                                 | ** **   | ** **                                                                                                | ** **   | ** **   | ** **  | **0.3**                               | ** ** | ** **  | ** **   |   | ** ** | **0.3** | ** ** |
| **Balance  at December 31, 2006**                                                                | ** **   | **180,519**                                                                                               | ** **   | **$**        | **2,738.6** | ** **                            | **$**      | **3,474.3** | ** **   | ** ** | **$** | **(1,603.6** | ) | ** ** | **$** | **4,609.3** | ** ** |

 

*See Notes to Consolidated Financial Statements.*

71

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CONSOLIDATEDSTATEMENTS OF CAPITALIZATION

***Constellation Energy Group, Inc. and Subsidiaries***
| ***At December 31,***                                                                                                                               | ** ** | **2006**                 | ** **  | **2005**   | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------|-------------|------------|------------|
| ** **                                                                                                                                                    | ** ** | ***(In millions)*** | ** **  |
| **Long-Term Debt**                                                                                                                                            | ** ** | ** **               | ** **  | ** ** | ** ** |
| Long-term debt of Constellation Energy                                                                                                                        |       |                     |        |       |       |
| 6.35% Fixed-Rate Notes, due April 1, 2007                                                                                                                | ** ** | **$**                    | **600.0**   |       | $          | 600.0 |   |
| 6.125% Fixed-Rate Notes, due September 1, 2009                                                                                                           | ** ** | **500.0**                |        | 500.0      |       |
| 7.00% Fixed-Rate Notes, due April 1, 2012                                                                                                                | ** ** | **700.0**                |        | 700.0      |       |
| 4.55% Fixed-Rate Notes, due June 15, 2015                                                                                                                | ** ** | **550.0**                |        | 550.0      |       |
| 7.60% Fixed-Rate Notes, due April 1, 2032                                                                                                                | ** ** | **700.0**                |        | 700.0      |       |
| Fair Value of Interest Rate Swaps                                                                                                                             | ** ** | **(7.1**                 | **)**       | (0.9       | )          |
| Total long-term debt of Constellation Energy                                                                                                                  | ** ** | **3,042.9**              |        | 3,049.1    |       |
| Long-term debt of nonregulated businesses                                                                                                                     |       |                     |        |       |       |
| Tax-exempt debt transferred from BGE effective July 1, 2000                                                                                              |       |                     |        |       |       |
| Pollution control loan, due July 1, 2011                                                                                                                 | ** ** | **36.0**                 |        | 36.0       |       |
| Port facilities loan, due June 1, 2013                                                                                                                   | ** ** | **48.0**                 |        | 48.0       |       |
| 4.10% Pollution control loan, due July 1, 2014                                                                                                           | ** ** | **20.0**                 |        | 20.0       |       |
| 5.55% Pollution control revenue refunding loan, due July 15, 2014                                                                                        | ** ** | **—**               |        | 47.0       |       |
| Economic development loan, due December 1, 2018                                                                                                          | ** ** | **35.0**                 |        | 35.0       |       |
| 6.00% Pollution control revenue refunding loan, due April 1, 2024                                                                                        | ** ** | **—**               |        | 75.0       |       |
| Floating-rate pollution control loan, due June 1, 2027                                                                                                   | ** ** | **8.8**                  |        | 8.8        |       |
| Tax-exempt variable rate notes, due April 1, 2024                                                                                                        | ** ** | **75.0**                 | ** **  | **—** | ** ** |
| Tax-exempt variable rate notes, due December 1, 2025                                                                                                     | ** ** | **47.0**                 | ** **  | **—** | ** ** |
| District Cooling facilities loan, due December 1, 2031                                                                                                   | ** ** | **25.0**                 |        | 25.0       |       |
| CEP credit facility loan, due October 31, 2010                                                                                                           | ** ** | **22.0**                 | ** **  | **—** | ** ** |
| 4.875% Inflation protection loan due February 15, 2012                                                                                                   | ** ** | **—**               |        | 12.0       |       |
| 5.00% Mortgage note, due July 5, 2010                                                                                                                    | ** ** | **7.5**                  |        | 12.8       |       |
| 4.25% Mortgage note, due March 15, 2009                                                                                                                  | ** ** | **1.3**                  |        | 1.9        |       |
| 7.3% Fixed Rate Note, due June 1, 2012                                                                                                                   | ** ** | **1.8**                  | ** **  | **—** | ** ** |
| South Carolina synthetic fuel facility loan, due January 15, 2008  (imputed interest rate of 3.47%)                                                      | ** ** | **20.0**                 |        | 36.0       |       |
| Total long-term debt of nonregulated businesses                                                                                                               | ** ** | **347.4**                |        | 357.5      |       |
| First Refunding Mortgage Bonds of BGE                                                                                                                         |       |                     |        |       |       |
| Remarketed floating-rate series, due September 1, 2006                                                                                                   | ** ** | **—**               |        | 97.4       |       |
| 71¤2% Series, due January 15, 2007                                                                                                                  | ** ** | **121.4**                |        | 122.0      |       |
| 65¤8% Series, due March 15, 2008                                                                                                                    | ** ** | **123.1**                |        | 123.4      |       |
| Total  First Refunding Mortgage Bonds of BGE                                                                                                                  | ** ** | **244.5**                |        | 342.8      |       |
| Other long-term debt of BGE                                                                                                                                   |       |                     |        |       |       |
| 5.25% Notes, due December 15, 2006                                                                                                                       | ** ** | **—**               |        | 300.0      |       |
| 5.90% Notes, due October 1, 2016                                                                                                                         | ** ** | **300.0**                | ** **  | **—** | ** ** |
| 5.20% Notes, due June 15, 2033                                                                                                                           | ** ** | **200.0**                |        | 200.0      |       |
| 6.35% Notes, due October 1, 2036                                                                                                                         | ** ** | **400.0**                | ** **  | **—** | ** ** |
| Medium-term notes, Series B                                                                                                                              | ** ** | **—**               |        | 12.0       |       |
| Medium-term notes, Series D                                                                                                                              | ** ** | **—**               |        | 10.0       |       |
| Medium-term notes, Series E                                                                                                                              | ** ** | **174.5**                |        | 199.5      |       |
| Medium-term notes, Series G                                                                                                                              | ** ** | **140.0**                |        | 140.0      |       |
| Total other long-term debt of BGE                                                                                                                             | ** ** | **1,214.5**              |        | 861.5      |       |
| 6.20% deferrable interest subordinated debentures due October 15,  2043 to BGE wholly owned BGE Capital Trust II relating to trust preferred  securities | ** ** | **257.7**                |        | 257.7      |       |
| Unamortized discount and premium                                                                                                                              | ** ** | **(5.9**                 | **)**       | (8.0       | )          |
| Current portion of long-term debt                                                                                                                             | ** ** | **(878.8**               | **)**       | (491.3     | )          |
| Total  long-term debt                                                                                                                                         | ** ** | **$**                    | **4,222.3** |       | $          | 4,369.3 |   |

 

 

*See Notesto Consolidated Financial Statements.*

*continued on next page*

72

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CONSOLIDATED STATEMENTS OFCAPITALIZATION

***Constellation EnergyGroup, Inc. and Subsidiaries***
| ***At December 31,***                                                                                                                                                                                                                                                                                                                                                                                                                                                            | ** ** | **2006**                 | ** **  | **2005**   | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------|-------------|------------|------------|
| ** **                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 | ** ** | ***(In millions)*** | ** **  |
| **Minority Interests**                                                                                                                                                                                                                                                                                                                                                                                                                                                                     | ** ** | **$**                    | **94.5**    |       | $          | 22.4 |   |
| **BGE Preference Stock**                                                                                                                                                                                                                                                                                                                                                                                                                                                                   | ** ** | ** **               | ** **  | ** ** | ** ** |
| Cumulative preference stock  not subject to mandatory redemption, 6,500,000 shares authorized 7.125%, 1993  Series, 400,000 shares outstanding, callable at $102.49 per share until  June 30, 2007, and at lesser amounts thereafter                                                                                                                                                                                                                                                  | ** ** | **40.0**                 |        | 40.0       |       |
| 6.97%, 1993 Series, 500,000  shares outstanding, callable at $102.44 per share until September 30,  2007, and at lesser amounts thereafter                                                                                                                                                                                                                                                                                                                                            | ** ** | **50.0**                 |        | 50.0       |       |
| 6.70%, 1993 Series, 400,000  shares outstanding, callable at $102.35 per share until December 31,  2007, and at lesser amounts thereafter                                                                                                                                                                                                                                                                                                                                             | ** ** | **40.0**                 |        | 40.0       |       |
| 6.99%, 1995 Series, 600,000  shares outstanding, callable at $103.15 per share until September 30,  2007, and at lesser amounts thereafter                                                                                                                                                                                                                                                                                                                                            | ** ** | **60.0**                 |        | 60.0       |       |
| Total preference stock not  subject to mandatory redemption                                                                                                                                                                                                                                                                                                                                                                                                                                | ** ** | **190.0**                |        | 190.0      |       |
| **Common Shareholders’ Equity**                                                                                                                                                                                                                                                                                                                                                                                                                                                       |       |                     |        |       |       |
| Common stock without par  value, 250,000,000 shares authorized; 180,519,180 and 178,300,844 shares  issued and outstanding at December 31, 2006 and 2005, respectively. (At  December 31, 2006, 3,739,214 shares were reserved for the long-term  incentive plans, 7,511,741 shares were reserved for the Shareholder  Investment Plan, 1,520,000 shares were reserved for the continuous offering  programs, and 1,546,143 shares were reserved for the employee savings plan.) | ** ** | **2,738.6**              |        | 2,620.8    |       |
| Retained earnings                                                                                                                                                                                                                                                                                                                                                                                                                                                                          | ** ** | **3,474.3**              |        | 2,810.2    |       |
| Accumulated other  comprehensive loss                                                                                                                                                                                                                                                                                                                                                                                                                                                      | ** ** | **(1,603.6**             | **)**       | (515.5     | )          |
| Total common shareholders’  equity                                                                                                                                                                                                                                                                                                                                                                                                                                                    | ** ** | **4,609.3**              |        | 4,915.5    |       |
| **Total Capitalization**                                                                                                                                                                                                                                                                                                                                                                                                                                                                   | ** ** | **$**                    | **9,116.1** |       | $          | 9,497.2 |   |

 

*See Notes to Consolidated FinancialStatements.*

73

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CONSOLIDATED STATEMENTS OFINCOME

***Baltimore Gas andElectric Company and Subsidiaries***
| ***Year Ended December 31,***           | ** ** | **2006**                 | ** **  | **2005** | ** ** | **2004** | ** ** |
|--------------------------------------------------------|------------|--------------------------|-------------|----------|------------|----------|------------|
| ** **                                             | ** ** | ***(In millions)*** | ** **  |
| **Revenues**                                           |       |                     |        |     |       |     |       |
| Electric  revenues                                     | ** ** | **$**                    | **2,115.9** |     | $          | 2,036.5  |       | $ | 1,967.7 |   |
| Gas revenues                                           | ** ** | **899.5**                |        | 972.8    |       | 757.0    |       |
| Total  revenues                                        | ** ** | **3,015.4**              |        | 3,009.3  |       | 2,724.7  |       |
| **Expenses**                                           |       |                     |        |     |       |     |       |
| Operating  Expenses                                    |       |                     |        |     |       |     |       |
| Electricity  purchased for resale                      | ** ** | **1,167.8**              |        | 1,068.9  |       | 1,034.0  |       |
| Gas purchased  for resale                              | ** ** | **581.5**                |        | 687.5    |       | 484.3    |       |
| Operations  and maintenance                            | ** ** | **496.1**                |        | 450.2    |       | 427.8    |       |
| Merger-related  costs                                  | ** ** | **4.7**                  |        | 5.4      |       | —   |       |
| Depreciation  and amortization                         | ** ** | **227.5**                |        | 232.4    |       | 242.3    |       |
| Taxes other  than income taxes                         | ** ** | **168.7**                |        | 168.4    |       | 164.9    |       |
| Total  expenses                                        | ** ** | **2,646.3**              |        | 2,612.8  |       | 2,353.3  |       |
| **Income from Operations**                             | ** ** | **369.1**                |        | 396.5    |       | 371.4    |       |
| **Other Income (Expense)**                             | ** ** | **6.0**                  |        | 5.9      |       | (6.4     | )          |
| **Fixed Charges**                                      |       |                     |        |     |       |     |       |
| Interest  expense                                      | ** ** | **104.6**                |        | 95.6     |       | 97.3     |       |
| Allowance for  borrowed funds used during construction | ** ** | **(2.0**                 | **)**       | (2.1     | )          | (1.1     | )          |
| Total fixed  charges                                   | ** ** | **102.6**                |        | 93.5     |       | 96.2     |       |
| **Income Before Income Taxes**                         | ** ** | **272.5**                |        | 308.9    |       | 268.8    |       |
| **Income Taxes**                                       |       |                     |        |     |       |     |       |
| Current                                                | ** ** | **(22.8**                | **)**       | 122.6    |       | 69.4     |       |
| Deferred                                               | ** ** | **126.6**                |        | (0.9     | )          | 34.9     |       |
| Investment  tax credit adjustments                     | ** ** | **(1.6**                 | **)**       | (1.8     | )          | (1.8     | )          |
| Total income  taxes                                    | ** ** | **102.2**                |        | 119.9    |       | 102.5    |       |
| **Net Income**                                         | ** ** | **170.3**                |        | 189.0    |       | 166.3    |       |
| **Preference Stock Dividends**                         | ** ** | **13.2**                 |        | 13.2     |       | 13.2     |       |
| **Earnings  Applicable to Common Stock**               | ** ** | **$**                    | **157.1**   |     | $          | 175.8    |       | $ | 153.1 |   |

 

CONSOLIDATEDSTATEMENTS OF COMPREHENSIVE INCOME

***Baltimore Gas and Electric Company and Subsidiaries***
| ***Year Ended December 31,***                                                           | ** ** | **2006**                 | ** ** | **2005** | ** ** | **2004** | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|--------------------------|------------|----------|------------|----------|------------|
| ** **                                                                                             | ** ** | ***(In millions)*** | ** ** |
| **Earnings Applicable to Common Stock**                                                                | ** ** | **$**                    | **157.1**  |     | $          | 175.8    |       | $ | 153.1 |   |
| Other  comprehensive income                                                                            |       |                     |       |     |       |     |       |
| Reclassification  of net gains on hedging instruments from OCI to net income, net of taxes of  $— | ** ** | **—**               |       | —   |       | (0.1     | )          |
| **Comprehensive Income**                                                                               | ** ** | **$**                    | **157.1**  |     | $          | 175.8    |       | $ | 153.0 |   |

 

*See Notesto Consolidated Financial Statements*

74

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CONSOLIDATED BALANCE SHEETS

***BaltimoreGas and Electric Company and Subsidiaries***
| ***At December 31,***                                                                 | ** ** | **2006**             | ** **  | **2005** | ** ** |
|-------------------------------------------------------------------------------------------------|------------|----------------------|-------------|----------|------------|
| *** ***                                                                                    | ** ** | ***(In  millions)*** | ** **  |
| Assets                                                                                          | ** ** | ** **           |        |     |       |
| **Current  Assets**                                                                             | ** ** | ** **           |        |     |       |
| Cash and  cash equivalents                                                                      | ** ** | **$**                | **10.9**    |     | $          | 15.1 |   |
| Accounts  receivable (net of allowance for uncollectibles of **$16.1** and $13.0, respectively) | ** ** | **344.7**            |        | 480.5    |       |
| Investment  in cash pool, affiliated company                                                    | ** ** | **60.6**             |        | —   |       |
| Accounts  receivable, affiliated companies                                                      | ** ** | **2.5**              |        | 1.8      |       |
| Fuel stocks                                                                                     | ** ** | **110.9**            |        | 102.7    |       |
| Materials  and supplies                                                                         | ** ** | **40.2**             |        | 40.1     |       |
| Prepaid  taxes other than income taxes                                                          | ** ** | **48.0**             |        | 45.7     |       |
| Regulatory  assets (net)                                                                        | ** ** | **62.5**             |        | —   |       |
| Other                                                                                           | ** ** | **35.2**             |        | 6.5      |       |
| Total  current assets                                                                           | ** ** | **715.5**            |        | 692.4    |       |
| **Investments  and Other Assets**                                                               | ** ** | ** **           |        |     |       |
| Regulatory  assets (net)                                                                        | ** ** | **389.0**            |        | 154.3    |       |
| Receivable,  affiliated company                                                                 | ** ** | **150.5**            |        | 154.7    |       |
| Other                                                                                           | ** ** | **127.5**            |        | 144.0    |       |
| Total  investments and other assets                                                             | ** ** | **667.0**            |        | 453.0    |       |
| **Utility  Plant**                                                                              | ** ** | ** **           |        |     |       |
| Plant in  service                                                                               | ** ** | ** **           |        |     |       |
| Electric                                                                                        | ** ** | **4,060.2**          |        | 3,891.1  |       |
| Gas                                                                                             | ** ** | **1,148.3**          |        | 1,116.7  |       |
| Common                                                                                          | ** ** | **444.6**            |        | 416.0    |       |
| Total plant  in service                                                                         | ** ** | **5,653.1**          |        | 5,423.8  |       |
| Accumulated  depreciation                                                                       | ** ** | **(1,994.7**         | **)**       | (1,923.8 | )          |
| Net plant in  service                                                                           | ** ** | **3,658.4**          |        | 3,500.0  |       |
| Construction  work in progress                                                                  | ** ** | **97.1**             |        | 93.9     |       |
| Plant held  for future use                                                                      | ** ** | **2.7**              |        | 2.8      |       |
| Net utility  plant                                                                              | ** ** | **3,758.2**          |        | 3,596.7  |       |
| **Total  Assets**                                                                               | ** ** | **$**                | **5,140.7** |     | $          | 4,742.1 |   |

 

*See Notesto Consolidated Financial Statements.*

75

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CONSOLIDATED BALANCE SHEETS

***Baltimore Gas and Electric Company and Subsidiaries***
| ***At December 31,***                                                                                                                           | ** ** | **2006**                 | ** **  | **2005** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------|-------------|----------|------------|
| ** **                                                                                                                                                | ** ** | ***(In millions)*** | ** **  |
| Liabilities and Equity                                                                                                                                    | ** ** | ** **               |        |     |       |
| **Current Liabilities**                                                                                                                                   | ** ** | ** **               |        |     |       |
| Current portion of long-term debt                                                                                                                         | ** ** | **$**                    | **258.3**   |     | $          | 469.6 |   |
| Accounts payable and accrued liabilities                                                                                                                  | ** ** | **187.3**                |        | 169.7    |       |
| Accounts payable and accrued liabilities, affiliated  companies                                                                                           | ** ** | **163.4**                |        | 152.8    |       |
| Borrowing from cash pool, affiliated company                                                                                                              |       | —                   |        | 3.2      |       |
| Customer deposits                                                                                                                                         | ** ** | **71.4**                 |        | 65.1     |       |
| Current portion of deferred income taxes                                                                                                                  | ** ** | **47.4**                 |        | 9.6      |       |
| Accrued taxes                                                                                                                                             | ** ** | **18.8**                 |        | 35.5     |       |
| Accrued expenses and other                                                                                                                                | ** ** | **79.5**                 |        | 70.0     |       |
| Total current liabilities                                                                                                                                 | ** ** | **826.1**                |        | 975.5    |       |
| **Deferred Credits and Other Liabilities**                                                                                                                | ** ** | ** **               |        |     |       |
| Deferred income taxes                                                                                                                                     | ** ** | **697.7**                |        | 608.9    |       |
| Payable, affiliated company                                                                                                                               | ** ** | **250.7**                |        | 277.7    |       |
| Deferred investment tax credits                                                                                                                           | ** ** | **13.5**                 |        | 15.1     |       |
| Other                                                                                                                                                     | ** ** | **14.0**                 |        | 19.0     |       |
| Total deferred credits and other liabilities                                                                                                              | ** ** | **975.9**                |        | 920.7    |       |
| **Long-term Debt**                                                                                                                                        | ** ** | ** **               |        |     |       |
| First refunding mortgage bonds of BGE                                                                                                                     | ** ** | **244.5**                |        | 342.8    |       |
| Other long-term debt of BGE                                                                                                                               | ** ** | **1,214.5**              |        | 861.5    |       |
| 6.20% deferrable interest subordinated debentures due  October 15, 2043 to wholly owned BGE Capital Trust II relating to trust  preferred securities | ** ** | **257.7**                |        | 257.7    |       |
| Long-term debt of nonregulated business                                                                                                                   | ** ** | **25.0**                 |        | 25.0     |       |
| Unamortized discount and premium                                                                                                                          | ** ** | **(2.9**                 | **)**       | (2.3     | )          |
| Current portion of long-term debt                                                                                                                         | ** ** | **(258.3**               | **)**       | (469.6   | )          |
| Total long-term debt                                                                                                                                      | ** ** | **1,480.5**              |        | 1,015.1  |       |
| **Minority Interest**                                                                                                                                     | ** ** | **16.7**                 |        | 18.3     |       |
| **Preference Stock Not Subject to Mandatory  Redemption**                                                                                                 | ** ** | **190.0**                |        | 190.0    |       |
| **Common Shareholder’s Equity**                                                                                                                      | ** ** | ** **               |        |     |       |
| Common stock                                                                                                                                              | ** ** | **912.2**                |        | 912.2    |       |
| Retained earnings                                                                                                                                         | ** ** | **738.6**                |        | 709.6    |       |
| Accumulated other comprehensive income                                                                                                                    | ** ** | **0.7**                  |        | 0.7      |       |
| Total common shareholder’s equity                                                                                                                    | ** ** | **1,651.5**              |        | 1,622.5  |       |
| **Commitments, Guarantees, and Contingencies (see  Note 12)**                                                                                             | ** ** | ** **               |        |     |       |
| **Total  Liabilities and Equity**                                                                                                                         | ** ** | **$**                    | **5,140.7** |     | $          | 4,742.1 |   |

 

*See Notesto Consolidated Financial Statements.*

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CONSOLIDATED STATEMENTS OF CASH FLOWS

***Baltimore Gas and Electric Company and Subsidiaries***
| ***Year Ended December 31,***                                                                  | ** ** | **2006**                 | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------------------------------------------------------------------------------------------|------------|--------------------------|------------|----------|------------|----------|------------|
| *** ***                                                                                                  | ** ** | ***(In millions)*** | ** ** |
| **Cash Flows From Operating Activities**                                                                      | ** ** | ** **               |       |     |       |     |       |
| Net income                                                                                                    | ** ** | **$**                    | **170.3**  |     | $          | 189.0    |       | $ | 166.3 |   |
| Adjustments to reconcile  to net cash provided by operating activities                                        | ** ** | ** **               |       |     |       |     |       |
| Depreciation and amortization                                                                                 | ** ** | **241.1**                |       | 250.5    |       | 260.9    |       |
| Deferred income taxes                                                                                         | ** ** | **126.6**                |       | (0.9     | )          | 34.9     |       |
| Investment tax credit adjustments                                                                             | ** ** | **(1.7**                 | **)**      | (1.8     | )          | (1.8     | )          |
| Deferred fuel costs                                                                                           | ** ** | **(348.5**               | **)**      | (11.9    | )          | 6.0      |       |
| Defined benefit plan expenses                                                                                 | ** ** | **47.2**                 |       | 37.8     |       | 31.9     |       |
| Allowance for equity funds used during construction                                                           | ** ** | **(3.7**                 | **)**      | (3.9     | )          | (2.0     | )          |
| Changes in                                                                                                    | ** ** | ** **               |       |     |       |     |       |
| Accounts receivable                                                                                           | ** ** | **135.8**                |       | (98.7    | )          | (27.0    | )          |
| Receivables, affiliated companies                                                                             | ** ** | **(0.7**                 | **)**      | (0.8     | )          | 3.5      |       |
| Materials, supplies, and fuel stocks                                                                          | ** ** | **(8.2**                 | **)**      | (21.7    | )          | (28.4    | )          |
| Other current assets                                                                                          | ** ** | **(31.0**                | **)**      | (0.5     | )          | 1.0      |       |
| Accounts payable and accrued liabilities                                                                      | ** ** | **17.6**                 |       | 44.3     |       | 24.2     |       |
| Accounts payable and accrued liabilities, affiliated  companies                                               | ** ** | **10.6**                 |       | 6.7      |       | (5.6     | )          |
| Other current liabilities                                                                                     | ** ** | **(0.9**                 | **)**      | 12.0     |       | (10.3    | )          |
| Long-term receivables and payables, affiliated  companies                                                     | ** ** | **(70.1**                | **)**      | (42.9    | )          | (52.0    | )          |
| Other                                                                                                         | ** ** | **(27.5**                | **)**      | (37.4    | )          | (30.2    | )          |
| Net cash provided by operating activities                                                                     | ** ** | **256.9**                |       | 319.8    |       | 371.4    |       |
| **Cash Flows From Investing Activities**                                                                      | ** ** | ** **               |       |     |       |     |       |
| Utility construction expenditures (excluding equity  portion of allowance for funds used during construction) | ** ** | **(320.6**               | **)**      | (270.5   | )          | (246.4   | )          |
| Change in cash pool at parent                                                                                 | ** ** | **(63.8**                | **)**      | 131.1    |       | 102.3    |       |
| Sales of investments and other assets                                                                         | ** ** | **(0.4**                 | **)**      | 11.0     |       | 4.9      |       |
| Other                                                                                                         | ** ** | **10.3**                 |       | (10.4    | )          | 2.7      |       |
| Net cash used in investing activities                                                                         | ** ** | **(374.5**               | **)**      | (138.8   | )          | (136.5   | )          |
| **Cash Flows From Financing Activities**                                                                      | ** ** | ** **               |       |     |       |     |       |
| Proceeds from issuance of long-term debt                                                                      | ** ** | **700.0**                |       | —   |       | —   |       |
| Repayment of long-term debt                                                                                   | ** ** | **(445.3**               | **)**      | (41.6    | )          | (149.8   | )          |
| Preference stock dividends paid                                                                               | ** ** | **(13.2**                | **)**      | (13.2    | )          | (13.2    | )          |
| Distribution to parent                                                                                        | ** ** | **(128.1**               | **)**      | (119.3   | )          | (74.7    | )          |
| Net cash provided by (used in) financing activities                                                           | ** ** | **113.4**                |       | (174.1   | )          | (237.7   | )          |
| **Net  (Decrease) Increase in Cash and Cash Equivalents**                                                     | ** ** | **(4.2**                 | **)**      | 6.9      |       | (2.8     | )          |
| **Cash and  Cash Equivalents at Beginning of Year**                                                           | ** ** | **15.1**                 |       | 8.2      |       | 11.0     |       |
| **Cash and  Cash Equivalents at End of Year**                                                                 | ** ** | **$**                    | **10.9**   |     | $          | 15.1     |       | $ | 8.2 |   |
| **Other Cash Flow Information:**                                                                              | ** ** | ** **               |       |     |       |     |       |
| Cash paid during the year for:                                                                                | ** ** | ** **               |       |     |       |     |       |
| Interest (net of amounts capitalized)                                                                         | ** ** | **$**                    | **87.2**   |     | $          | 88.6     |       | $ | 95.5 |   |
| Income taxes                                                                                                  | ** ** | **$**                    | **18.7**   |     | $          | 123.3    |       | $ | 80.7 |   |

 

*See Notesto Consolidated Financial Statements.*

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Notes toConsolidated Financial Statements

**1**Significant AccountingPolicies

**Nature of OurBusiness**

ConstellationEnergy Group, Inc. (Constellation Energy) is an energy company thatconducts its business through various subsidiaries including a merchant energybusiness and Baltimore Gas and Electric Company (BGE). Our merchant energybusiness is a competitive provider of energy solutions for a variety ofcustomers. BGE is a regulated electric transmission and distribution utilitycompany and a regulated gas distribution utility company with a serviceterritory that covers the City of Baltimore and all or part of ten counties incentral Maryland. We describe our operating segments in *Note 3*.

This report is a combined report of Constellation Energy and BGE. Referencesin this report to “we” and “our” are to Constellation Energy and itssubsidiaries. References in this report to the “regulated business(es)” are toBGE.

**Termination ofMerger Agreement with FPL Group, Inc.**

On October 24, 2006, Constellation Energy and FPL Group, Inc.(FPL Group) agreed to terminate the Agreement and Plan of Merger the partieshad entered into on December 18, 2005.We discuss the terminated merger in more detail in *Note 15*.

**ConsolidationPolicy**

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

***Consolidation***

We use consolidation for two types of entities:

 ̈  subsidiaries (other than variable interest entities)in which we own a majority of the voting stock, and

 ̈  variable interest entities (VIEs) for which we arethe primary beneficiary. Financial Accounting Standards Board (FASB)Interpretation No. (FIN) 46R, *Consolidationof Variable Interest Entities*, requires us to use consolidation whenwe are the primary beneficiary of a VIE, which means that we have a controllingfinancial interest in a VIE. We discuss our investments in VIEs in more detailin *Note 4*.

Consolidation means that we combine the accounts of these entities withour accounts. Therefore, our consolidated financial statements include ouraccounts, the accounts of our majority-owned subsidiaries that are notVIEs, and the accounts of VIEs for which we are the primary beneficiary. Wehave not consolidated any entities for which we do not have a controllingvoting interest. We eliminate all intercompany balances and transactions whenwe consolidate these accounts.

***The EquityMethod***

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

 ̈  our interest in the entity as an investment in ourConsolidated Balance Sheets, and

 ̈  our percentage share of the earnings from the entityin our Consolidated Statements of Income.

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

***The Cost Method***

We usually use the cost method if we hold less than a 20% votinginterest in an investment. Under the cost method, we report our investment atcost in our Consolidated Balance Sheets. The only time we do not use thismethod is when we can exercise significant influence over the operations andpolicies of the company. If we have significant influence, accounting rules requireus to use the equity method.

***Sale ofSubsidiary Stock***

We may sell portions of our ownership interests through publicofferings of a subsidiary’s stock. We record any gains or losses on publicofferings in our Consolidated Statements of Income, as a component ofnon-operating income.

**Regulation ofElectric and Gas Business**

The MarylandPublic Service Commission (Maryland PSC) and the Federal Energy RegulatoryCommission (FERC) provide the final determination of the rates we charge ourcustomers for our regulated businesses. Generally, we use the same accountingpolicies and practices used by nonregulated companies for financial reportingunder accounting principles generally accepted in the United States of America.However, sometimes the Maryland PSC or the FERC orders an accounting treatmentdifferent from that used by nonregulated companies to determine the rates wecharge our customers.

When thishappens, we must defer (include as an asset or liability in our, and BGE’s,Consolidated Balance Sheets and exclude from our, and BGE’s, ConsolidatedStatements of Income) certain regulated business expenses and income asregulatory assets and liabilities. We have recorded these regulatory assets andliabilities in our, and BGE’s, Consolidated Balance Sheets in accordance withStatement of Financial Accounting Standards (SFAS) No. 71, *Accounting for the Effects of Certain Types ofRegulation.*

We summarize and discuss our regulatory assets and liabilities furtherin *Note 6*.

**Use of AccountingEstimates**

Management makes estimates and assumptions when preparing financialstatements under accounting principles generally 

78

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accepted in the United States of America. These estimates andassumptions affect various matters, including:

 ̈  our reported amounts of revenues and expenses in ourConsolidated Statements of Income during the reporting periods,

 ̈  our reported amounts of assets and liabilities in ourConsolidated Balance Sheets at the dates of the financial statements, and

 ̈  our disclosure of contingent assets and liabilitiesat the dates of the financial statements.

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

**Reclassifications**

We have reclassified certain prior-year amounts for comparativepurposes. These reclassifications primarily relate to operations that have beenclassified as discontinued operations in the current year and did not affectconsolidated net income for the years presented.

**Revenues**

***AccrualAccounting***

We recordrevenues from the sale of energy, energy-related products, and energyservices under the accrual method of accounting in the period when we deliverenergy commodities or products, render services, or settle contracts. We useaccrual accounting for our merchant energy and other nonregulated businesstransactions, including the generation or purchase and sale of electricity,gas, and coal as part of our physical delivery activities and for power, gas,and coal sales contracts that are not subject to mark-to-market accounting. Salescontracts that are eligible for accrual accounting include non-derivativetransactions and derivatives that qualify for and are designated as normalpurchases and normal sales of commodities that will be physically delivered. Werecord accrual revenues, including settlements with independent systemoperators, on a gross basis because we are a principal to the transaction andotherwise meet the requirements of Emerging Issues Task Force (EITF) 03-11,*Reporting Gains and Losses on DerivativeInstruments That Are Subject to FASB Statement No. 133, Accounting forDerivative Instruments and Hedging Activities, and Not Held for TradingPurposes,* and EITF 99-19, *ReportingRevenue Gross as a Principal versus Net as an Agent*.

We may make orreceive cash payments at the time we assume a power sale agreement for whichthe contract price differs from current market prices. We recognize the cashpayment at inception in our Consolidated Balance Sheets as an “Unamortizedenergy contract” asset or liability. We amortize these assets and liabilitiesinto revenues based on the expected cash flows provided by the contracts.

During 2006 and 2005, we terminated or restructured in-the-moneycontracts in exchange for upfront cash payments and a reduction or cancellationof future performance obligations. The termination or restructuring ofcontracts allowed us to lower our exposure to performance risk under thesecontracts, and resulted in the realization of $56.7 million of pre-tax earningsin 2006 and $77.0 million of pre-tax earnings in 2005 that would havebeen recognized over the life of these contracts.

***Mark-to-MarketAccounting***

We recordrevenues using the mark-to-market method of accounting for derivative contractsfor which we are not permitted to use accrual accounting or hedge accounting.We discuss our use of hedge accounting in the *Derivativesand Hedging Activities* section later in this Note. Thesemark-to-market activities include derivative contracts for energy and otherenergy-related commodities. Under the mark-to-market method ofaccounting, we record the fair value of these derivatives as mark-to-marketenergy assets and liabilities at the time of contract execution. Our wholesalemarketing, risk management, and trading operation records changes inmark-to-market energy assets and liabilities on a net basis in “Nonregulatedrevenues” in our Consolidated Statements of Income. Our retail competitivesupply operation records changes in sale contracts accounted for asmark-to-market in “Nonregulated revenues” in our Consolidated Statements ofIncome.

Mark-to-marketenergy assets and liabilities consist of derivative contracts. While some ofthese contracts represent commodities or instruments for which prices areavailable from external sources, other commodities and certain contracts arenot actively traded and are valued using modeling techniques to determineexpected future market prices, contract quantities, or both. The market pricesand quantities used to determine fair value reflect management’s best estimateconsidering various factors, including closing exchange and over-the-counterquotations, time value, and volatility factors. However, future market pricesand actual quantities will vary from those used in recording mark-to-marketenergy assets and liabilities, and it is possible that such variations could bematerial.

Mark-to-market revenues include:

 ̈  gains or losses on new transactions at origination tothe extent permitted by applicable accounting rules,

 ̈  unrealized gains and losses from changes in the fairvalue of open contracts,

 ̈  net gains and losses from realized transactions, and

 ̈  changes in valuation adjustments.

Originationgains, which are included in mark-to-market revenues, ariseprimarily from contracts that our wholesale marketing, risk management, andtrading operation structures to meet the risk management needs of ourcustomers. Transactions that result in origination gains may be unique andprovide the potential for individually significant gains from a singletransaction.

Origination gains represent the initial fair value recognized on thesestructured transactions. The recognition of origination gains is dependent onthe existence of observable market data that validates the initial fair valueof the contract. Origination gains were:

 ̈  $13.5 million pre-tax in 2006,

 ̈  $61.6 million pre-tax in 2005, and

 ̈  $19.7 million pre-tax in 2004.

Origination gains arose primarily from:

 ̈  3 transactions completed in2006, of which no transaction contributed in excess of $10 million pre-tax,

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 ̈  6 transactions completed in 2005, one of whichcontributed approximately $35 million pre-tax, and

 ̈  7 transactions completed in2004, of which no transaction contributed in excess of $10 million pre-tax.

*ValuationAdjustments*

We recordvaluation adjustments to reflect uncertainties associated with certainestimates inherent in the determination of the fair value of mark-to-marketenergy assets and liabilities. To the extent possible, we utilize market-baseddata together with quantitative methods for both measuring the uncertaintiesfor which we record valuation adjustments and determining the level of suchadjustments and changes in those levels.

We describe below the main types of valuation adjustments we record andthe process for establishing each. Generally, increases in valuationadjustments reduce our earnings, and decreases in valuation adjustmentsincrease our earnings. However, all or a portion of the effect on earnings ofchanges in valuation adjustments may be offset by changes in the value of theunderlying positions.

 ̈  Close-out adjustment—represents the estimated cost toclose out or sell to a third-party open mark-to-market positions. Thisvaluation adjustment has the effect of valuing “long” positions (the purchaseof a commodity) at the bid price and “short” positions (the sale of acommodity) at the offer price. We compute this adjustment based on our estimateof the bid/offer spread for each commodity and option price and the absolutequantity of our net open positions for each year. The level of total close-outvaluation adjustments increases as we have larger unhedged positions, bid-offerspreads increase, or market information is not available, and it decreases aswe reduce our unhedged positions, bid-offer spreads decrease, or marketinformation becomes available. To the extent that we are not able to obtainobservable market information for similar contracts, the close-out adjustmentis equivalent to the initial contract margin, thereby recording no gain or lossat inception. In the absence of observable market information, there is apresumption that the transaction price is equal to the market value of thecontract, and therefore we do not recognize a gain or loss at inception. Werecognize such gains or losses in earnings as we realize cash flows under thecontract or when observable market data becomes available.

 ̈  Credit-spread adjustment—forrisk management purposes we compute the value of our mark-to-market energyassets and liabilities using a risk-free discount rate. In order to computefair value for financial reporting purposes, we adjust the value of ourmark-to-market energy assets to reflect the credit-worthiness of eachcustomer (counterparty) based upon either published credit ratings, orequivalent internal credit ratings and associated default probabilitypercentages. We compute this adjustment by applying the appropriate defaultprobability percentage to our outstanding credit exposure, net of collateral,for each counterparty. The level of this adjustment increases as our credit exposureto counterparties increases, the maturity terms of our transactions increase,or the credit ratings of our counterparties deteriorate, and it decreases whenour credit exposure to counterparties decreases, the maturity terms of ourtransactions decrease, or the credit ratings of our counterparties improve.

*FinancialStatement Presentation*

Certain transactions entered into under master agreements and otherarrangements provide our wholesale competitive supply operation with a right ofsetoff in the event of bankruptcy or default by the counterparty. We reportsuch transactions net in our Consolidated Balance Sheets in accordance withFASB Interpretation No. 39, *Offsettingof Amounts Related to Certain Contracts*.

***Equity inEarnings***

We include equity in earnings from our investments in qualifyingfacilities and power projects in “Nonregulated revenues” in our ConsolidatedStatements of Income in the period they are earned.

**Fuel and PurchasedEnergy Expenses**

We incur costs for:

 ̈  the fuel we use to generate electricity,

 ̈  purchases of electricity from others, and

 ̈  natural gas and coal that we resell.

These costs areincluded in “Fuel and purchased energy expenses” in our Consolidated Statementsof Income. We discuss certain of these separately below. We also includecertain non-fuel direct costs, such as ancillary services, transmission costs,and brokerage fees in “Fuel and purchased energy expenses” in our ConsolidatedStatements of Income.

Our retail competitive supply operation records changes in purchasecontracts accounted for as mark-to-market in “Fuel and purchased energyexpenses” in our Consolidated Statements of Income.

***Fuel Used toGenerate Electricity and Purchases of***Electricity

*NonregulatedBusinesses*

We assemble avariety of power supply resources, including baseload, intermediate, andpeaking plants that we own, as well as a variety of power supply contracts thatmay have similar characteristics, in order to enable us to meet our customers’energy requirements, which vary on an hourly basis. The amount of powerpurchased depends on a number of factors, including the capacity andavailability of our power plants, the level of customer demand, and therelative economics of generating power versus purchasing power from the spotmarket.

We also haveacquired contracts and certain power purchase agreements that qualify asoperating leases. Under these operating leases, we record fuel and purchasedenergy expense as we make fixed capacity payments, as well as variable paymentsbased on the actual output of the plants.

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We may make or receive cash payments at the time we acquire a contractor assume a power purchase agreement when the contract price differs frommarket prices at closing. We recognize the cash payment or receipt at inceptionin our Consolidated Balance Sheets as an “Unamortized energy contract” asset(payment) or liability (receipt). We amortize these assets and liabilities intofuel and purchased energy expenses based on the expected cash flows provided bythe contracts.

*RegulatedElectric*

BGE is obligatedto provide market-based standard offer service to residential and smallcommercial customers for the indefinite future, and for large commercial andindustrial customers for varying periods beyond June 30, 2004, dependingon customer load. The Provider of Last Resort (POLR) rates charged during thesetime periods will recover BGE’s wholesale power supply costs and include anadministrative fee. The administrative fee includes a shareholder returncomponent and an incremental cost component. Pursuant to Senate Bill 1, theenergy legislation enacted in Maryland in June 2006, collection of theshareholder return component of the administrative fee for residential POLRservice will be suspended beginning January 1, 2007 for a 10-yearperiod.

In accordancewith the POLR settlement agreement approved by the Maryland PSC, BGE defers thedifference between certain of its actual costs related to the electriccommodity and what it collects from customers under the commodity charge in agiven period. BGE either bills or refunds its customers the difference in thefuture. In addition, Senate Bill 1 imposed a 15% rate cap for BGEresidential electric customers from July 1, 2006 until May 31, 2007.We discuss this in more detail in *Note 6*.

BGE’s obligation to provide market-based standard offer serviceto its largest commercial and industrial customers expired May 31, 2005.BGE continues to provide an hourly priced market-based standard offerservice to those customers.

*Regulated Gas*

BGE charges its gas customers for the natural gas they purchase fromBGE using “gas cost adjustment clauses” set by the Maryland PSC. Under theseclauses, BGE defers the difference between certain of its actual costs relatedto the gas commodity and what it collects from customers under the commoditycharge in a given period. BGE either bills or refunds its customers thedifference in the future. The Maryland PSC approved a modification of the gascost adjustment clauses to provide a market-based rates incentivemechanism. Under the market-based rates incentive mechanism, BGE’s actualcost of gas is compared to a market index (a measure of the market price of gasin a given period). The difference between BGE’s actual cost and the marketindex is shared equally between shareholders and customers. Effective November 2001,the Maryland PSC approved a settlement that modifies certain provisions of themarket-based rates incentive mechanism. These provisions require that BGEsecure fixed-price contracts for at least 10%, but not more than 20%, offorecasted system supply requirements for the November through March period.These fixed-price contracts are not subject to sharing under the market-basedrates incentive mechanism.

**Derivatives and Hedging Activities**

We are exposed to market risk, including changes in interest rates andthe impact of market fluctuations in the price and transportation costs ofelectricity, natural gas, and other commodities as discussed further in *Note 13*. In order to manage theserisks, we use both derivative and non-derivative contracts that may provide forsettlement in cash or by delivery of a commodity, including:

 ̈  forwardcontracts, which commit us to purchase or sell energy commodities in thefuture,

 ̈  futurescontracts, which are exchange-traded standardized commitments to purchaseor sell a commodity or financial instrument, or to make a cash settlement, at aspecific price and future date,

 ̈  swapagreements, which require payments to or from counterparties based upon thedifferential between two prices for a predetermined contractual (notional)quantity, and

 ̈  optioncontracts, which convey the right to buy or sell a commodity, financialinstrument, or index at a predetermined price.

SFAS No. 133*, Accounting for Derivative Instruments and HedgingActivities,* as amended, requires that we recognize at fair value allderivatives not qualifying for accrual accounting under the normal purchase andnormal sale exception. We record derivatives that are designated as hedges in “Riskmanagement assets or liabilities” and derivatives not designated as hedges in “Mark-to-marketenergy assets or liabilities” in our Consolidated Balance Sheets.

We recordchanges in the value of derivatives that are not designated as cash-flow hedgesin earnings during the period of change. We record changes in the fair value ofderivatives designated as cash-flow hedges that are effective in offsetting thevariability in cash flows of forecasted transactions in other comprehensiveincome until the forecasted transactions occur. At the time the forecastedtransactions occur, we reclassify the amounts recorded in other comprehensiveincome into earnings. We record the ineffective portion of changes in the fairvalue of derivatives used as cash-flow hedges immediately in earnings.

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We summarize our cash-flow hedging activitiesunder SFAS No. 133 and the income statement classification of amountsreclassified from “Accumulated other comprehensive income (loss)” as follows:
| **Risk**                                               | ** ** | **Derivative**                                          | ** ** | **Income Statement  Classification** |
|--------------------------------------------------------|------------|---------------------------------------------------------|------------|--------------------------------------|
| Interest rate risk associated  with new debt issuances |       | Interest rate swaps                                     |       | Interest expense                     |
| Interest rate risk associated  with variable-rate debt |       | Interest rate swaps                                     |       | Interest expense                     |
| Nonregulated energy sales                              |       | Futures and forward contracts                           |       | Nonregulated revenues                |
| Nonregulated fuel and energy  purchases                |       | Futures and forward contracts                           |       | Fuel and purchased energy expenses   |
| Nonregulated gas purchases for  resale                 |       | Futures and forward contracts and price and basis swaps |       | Fuel and purchased energy expenses   |
| Regulated gas purchases for  resale                    |       | Price and basis swaps                                   |       | Fuel and purchased energy expenses   |
| Regulated electricity  purchases for resale            |       | Price and basis swaps                                   |       | Fuel and purchased energy expenses   |

 

We designate certain derivatives as fairvalue hedges. We record changes in the fair value of these derivatives andchanges in the fair value of the hedged assets or liabilities in earnings asthe changes occur. We summarize our fair value hedging activities and theincome statement classification of changes in the fair value of these hedges andthe related hedged items as follows:
| **Risk**                                     | ** ** | **Derivative**                              | ** ** | **Income Statement  Classification**                         |
|----------------------------------------------|------------|---------------------------------------------|------------|--------------------------------------------------------------|
| Optimize mix of fixed and floating-rate debt |       | Interest rate swaps                         |       | Interest expense                                             |
| Value of natural gas in storage              |       | Forward contracts and price and basis swaps |       | Nonregulated revenues and Fuel and purchased energy expenses |

 

We record changes in the fair value of interest rate swaps and the debtbeing hedged in “Risk management assets and liabilities” and “Long-term debt”and changes in the fair value of the gas being hedged and related derivativesin “Fuel stocks” and “Risk management assets and liabilities” in ourConsolidated Balance Sheets. In addition, we record the difference betweeninterest on hedged fixed-rate debt and floating-rate swaps in “Interest expense”in the periods that the swaps settle.

**Unamortized Energy Assets and Liabilities**

Unamortized energy contract assets and liabilities represent theremaining unamortized balance of non-derivative energy contracts that weacquired or derivatives designated as normal purchases and normal sales that wehad previously recorded as “Mark-to-market energy assets or liabilities” or “Riskmanagement assets and liabilities.” The initial amount recorded represents thefair value of the contract at the time of acquisition or designation, and thebalance is amortized over the life of the contract in relation to the presentvalue of the underlying cash flows. The amortization of these values isdiscussed in the *Revenues* and *Fuel and Purchased Energy Expenses*sections of this Note.

**Credit Risk**

Credit risk isthe loss that may result from counterparty non-performance. We are exposed tocredit risk, primarily through our merchant energy business. We use creditpolicies to manage our credit risk, including utilizing an established creditapproval process, daily monitoring of counterparty limits, employing creditmitigation measures such as margin, collateral or prepayment arrangements, andusing master netting agreements. We measure credit risk as the replacement costfor open energy commodity and derivative positions (both mark-to-market andaccrual) plus amounts owed from counterparties for settled transactions. Thereplacement cost of open positions represents unrealized gains, less anyunrealized losses where we have a legally enforceable right of setoff.

Electric and gas utilities, municipalities, cooperatives, generationowners, and energy marketers comprise the majority of counterparties underlyingour assets from our wholesale marketing and risk management activities. We heldcash collateral from these counterparties totaling $252.6 million as of December 31,2006 and $388.4 million as of December 31, 2005. These amounts areincluded in “Customer deposits and collateral” in our Consolidated BalanceSheets.

**Taxes**

We summarize our income taxes in *Note 10*.BGE and our other subsidiaries record their allocated share of our consolidatedfederal income tax liability using the percentage complementary methodspecified in U.S. income tax regulations. As you read this section, it may behelpful to refer to *Note 10*.

***Income TaxExpense***

We have two categories of income tax expense—current and deferred. Wedescribe each of these below:

 ̈  currentincome tax expense consists solely of regular tax less applicable tax credits,and

 ̈  deferredincome tax expense is equal to the changes in the net deferred income taxliability, excluding amounts charged or credited to accumulated othercomprehensive income. Our deferred income tax expense is increased or reducedfor changes to the “Income taxes recoverable 

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through future rates (net)” regulatory asset (described below) duringthe year.

***Tax Credits***

We havedeferred the investment tax credits associated with our regulated business andassets previously held by our regulated business in our Consolidated BalanceSheets. The investment tax credits are amortized evenly to income over the lifeof each property. We reduce current income tax expense in our ConsolidatedStatements of Income for the investment tax credits and other tax creditsassociated with our nonregulated businesses.

We have certain investments in facilities that manufacture solidsynthetic fuel produced from coal as defined under the Internal Revenue Codefor which we claim tax credits on our Federal income tax return. We recognizethe tax benefit of these credits in our Consolidated Statements of Income whenwe believe it is highly probable that the credits will be sustained.

***Deferred IncomeTax Assets and Liabilities***

We must reportsome of our revenues and expenses differently for our financial statements thanfor income tax return purposes. The tax effects of the temporary differences inthese items are reported as deferred income tax assets or liabilities in ourConsolidated Balance Sheets. We measure the deferred income tax assets andliabilities using income tax rates that are currently in effect.

A portion of our total deferred income tax liability relates to ourregulated business, but has not been reflected in the rates we charge ourcustomers. We refer to this portion of the liability as “Income taxesrecoverable through future rates (net).” We have recorded that portion of thenet liability as a regulatory asset in our Consolidated Balance Sheets. Wediscuss this further in *Note 6*.

***State and LocalTaxes***

State and localincome taxes are included in “Income taxes” in our Consolidated Statements ofIncome.

BGE also pays Maryland public service company franchise tax ondistribution, and delivery of electricity and natural gas. We include thefranchise tax in “Taxes other than income taxes” in our Consolidated Statementsof Income.

**Earnings Per Share**

Basic earningsper common share (EPS) is computed by dividing earnings applicable to commonstock by the weighted-average number of common shares outstanding for theyear. Diluted EPS reflects the potential dilution of common stock equivalentshares that could occur if securities or other contracts to issue common stockwere exercised or converted into common stock.

Our dilutive common stock equivalent sharesconsist of stock options and other stock-based compensation awards. Thefollowing table presents stock options that were not dilutive and were excludedfrom the computation of diluted EPS in each period, as well as the dilutivecommon stock equivalent shares as follows:
| ***Year Ended December 31,*** | ** ** | **2006**                 | ** ** | **2005** | ** ** | **2004** | ** ** |
|----------------------------------------------|------------|--------------------------|------------|----------|------------|----------|------------|
| ** **                                   | ** ** | ***(In millions)*** | ** ** |
| Non-dilutive stock options                   |       |                     | **—** |     |       |     | 0.1        |   |   |   | — |   |   |
| Dilutive common stock equivalent shares      | ** ** | ** **               | **2.0**    |     |       |     | 2.2        |   |   |   | 1.0 |   |   |

 

**Stock-Based Compensation**

Under ourlong-term incentive plans, we have granted stock options, performance-basedunits, performance and service-based restricted stock, and equity toofficers, key employees, and members of the Board of Directors. We discussthese awards in more detail in *Note 14*.

We elected toearly adopt SFAS No. 123 Revised (SFAS No. 123R), *Share-Based Payment,* on October 1,2005, which was prior to the required effective date of January 1, 2006.SFAS No. 123R requires companies to recognize compensation expense for allequity-based compensation awards issued to employees that are expected tovest. Equity-based compensation awards include stock options, restrictedstock, and any other share-based payments. We recognized a small,favorable cumulative effect of change in accounting principle of$0.2 million after-tax due to the requirement to reduce compensationexpense for estimated forfeitures relating to outstanding unvested service-basedrestricted stock awards and performance-based unit awards at October 1,2005.

Under SFAS No. 123R, we recognize compensation cost ratably or intranches (depending if the award has cliff or graded vesting) over the periodduring which an employee is required to provide service in exchange for theaward, which is typically a one to five-year period. We use a forfeitureassumption to estimate the number of awards that are expected to vest duringthe service period, and ultimately true-up the estimated expense to the actualexpense associated with vested awards. We estimate the fair value of stockoption awards on the date of grant using the Black-Scholes option-pricingmodel and we remeasure the fair value of liability awards each reportingperiod. The following table presents the pro-forma effect on net income andearnings per share for all outstanding stock options and stock awards in eachperiod that the fair value provisions of SFAS No. 123R were not in effect.We do not capitalize any portion of our stock-based compensation.

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| ***Year Ended December 31,***                                                                                                           | ** ** | **2005**                                                           | ** ** | **2004**   | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------|------------|------------|------------|
| ** **                                                                                                                                             | ** ** | ***(In millions, except  per share amounts)*** | ** ** |
| Net income, as reported                                                                                                                                |       | **$**                                                              | **623.1**  | ** ** | $          | 539.7 |   |
| Add: Actual stock-based compensation expense determined under  intrinsic value method and included in reported net income, net of related  tax effects |       | **17.8**                                                           | *****      | 13.2       |       |
| Deduct: Pro-forma stock-based compensation expense  determined under fair value based method for all awards, net of related tax  effects               |       | **(24.5**                                                          | **)***     | (21.3      | )          |
| Pro-forma net income                                                                                                                                   |       | **$**                                                              | **616.4**  | ** ** | $          | 531.6 |   |
| Earnings per share:                                                                                                                                    |       | ** **                                                         | ** ** |       |       |
| Basic—as  reported                                                                                                                                |       | **$**                                                              | **3.51**   | ** ** | $          | 3.14 |   |
| Basic—pro-forma                                                                                                                                   |       | **$**                                                              | **3.47**   | ** ** | $          | 3.09 |   |
| Diluted—as  reported                                                                                                                              |       | **$**                                                              | **3.47**   | ** ** | $          | 3.12 |   |
| Diluted—pro-forma                                                                                                                                 |       | **$**                                                              | **3.43**   | ** ** | $          | 3.07 |   |

** Represents expense for the nine monthsended September 30, 2005, which was prior to adoption of SFAS No. 123R*

**Cash and Cash Equivalents**

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

**Accounts Receivable and Allowance forUncollectibles**

Accounts receivable, which includes cash collateral posted in ourmargin account with a third-party broker, are stated at the historical carryingamount net of write-offs and allowance for uncollectibles. We establish anallowance for uncollectibles based on our expected exposure to the credit riskof customers based on a variety of factors.

**Materials, Supplies, and Fuel Stocks**

We record our fuel stocks, emissions credits, coal held for resale, andmaterials and supplies at the lower of cost or market. We determine cost usingthe average cost method for all of our inventory other than our coal held forresale for which we use the specific identification method.

**Financial Investments**

In *Note 4*, we summarize the financialinvestments that are in our Consolidated Balance Sheets.

SFAS No. 115, *Accounting forCertain Investments in Debt and Equity Securities,* appliesparticular requirements to some of our investments in debt and equity securities.We report those investments at fair value, and we use either specificidentification or average cost to determine their cost for computing realizedgains or losses.

***Available-for-SaleSecurities***

We classify ourinvestments in the nuclear decommissioning trust funds as available-for-salesecurities. We describe the nuclear decommissioning trusts and the relatedasset retirement obligations later in this Note. In addition, we haveinvestments in marketable equity securities and trust assets securing certainexecutive benefits that are classified as available-for-sale securities.

We include any unrealized gains or losses on our available-for-salesecurities in “Accumulated other comprehensive income” in our ConsolidatedStatements of Common Shareholders’ Equity and Comprehensive Income andConsolidated Statements of Capitalization.

**Evaluation of Assets for Impairment and OtherThan Temporary Decline in Value**

*Long-LivedAssets*

We are requiredto evaluate certain assets that have long lives (for example, generatingproperty and equipment and real estate) to determine if they are impaired whencertain conditions exist. SFAS No. 144, *Accountingfor the Impairment or Disposal of Long-Lived Assets,* provides theaccounting requirements for impairments of long-lived assets and proved gasproperties. We are required to test our long-lived assets and proved gasproperties for recoverability whenever events or changes in circumstancesindicate that their carrying amount may not be recoverable.

We determine iflong-lived assets and proved gas properties are impaired by comparing theirundiscounted expected future cash flows to their carrying amount in ouraccounting records. We would record an impairment loss if the undiscountedexpected future cash flows were less than the carrying amount of the asset.Cash flows for long-lived assets, or a group of long-lived assets, aredetermined at the lowest level for which identifiable cash flows are largelyindependent of the cash flows of other assets and liabilities. Proven gas properties’cash flows are determined at the field level. Undiscounted expected future cashflows include risk-adjusted probable and possible reserves. We are alsorequired to evaluate our equity-method and cost-method investments (forexample, in partnerships that own power projects) for impairment. AccountingPrinciples Board (APB) No. 18, *TheEquity Method of Accounting for Investments in Common Stock* (APB No. 18),provides the accounting requirements for these investments. The standard fordetermining whether an impairment must be recorded under APB No. 18 iswhether the investment has experienced a loss in value that is considered an “otherthan a temporary” decline in value.

We are alsorequired to evaluate unproved gas producing properties at least annually todetermine if it is impaired under SFAS No. 19, *Financial Accounting and Reporting by Oil and Gas Producing Properties*.Impairment for unproved property occurs if there are no firm plans to continuedrilling, lease expiration is at risk, or historical experience necessitates avaluation allowance.

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

*Debt and EquitySecurities*

Our investments in debt and equity securities, which primarily consistof our nuclear decommissioning trust fund investments, are subject toimpairment evaluations under FASB Staff Position (FSP) FAS 115-1, *The Meaning of Other-Than-Temporary Impairment andIts Application to Certain Investments.* FSP FAS 115-1requires us to determine whether a decline in fair value of an investment belowthe amortized cost basis is other 

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than temporary. If we determine that the decline in fair value isjudged to be other than temporary, the cost basis of the investment must bewritten down to fair value as a new cost basis.

*IntangibleAssets*

Goodwill is the excess of the purchase price of an acquired businessover the fair value of the net assets acquired. We account for goodwill andother intangibles under the provisions of SFAS No. 142, *Goodwill and Other Intangible Assets.* Wedo not amortize goodwill. SFAS No. 142 requires us to evaluate goodwill forimpairment at least annually or more frequently if events and circumstancesindicate the business might be impaired. Goodwill is impaired if the carryingvalue of the business exceeds fair value. Annually, we estimate the fair valueof the businesses we have acquired using techniques similar to those used toestimate future cash flows for long-lived assets as previously discussed. Ifthe estimated fair value of the business is less than its carrying value, animpairment loss is required to be recognized to the extent that the carryingvalue of goodwill is greater than its fair value. SFAS No. 142 alsorequires the amortization of intangible assets with finite lives. We discussthe changes in our intangible assets in more detail in *Note 5*.

**Property, Plant and Equipment, Depreciation,Depletion, Amortization, and Accretion of Asset Retirement Obligations**

We report ourproperty, plant and equipment at its original cost, unless impaired under theprovisions of SFAS No. 144.

Our original costs include:

 ̈  materialand labor,

 ̈  contractorcosts, and

 ̈  constructionoverhead costs, financing costs, and costs for asset retirement obligations(where applicable).

We own anundivided interest in the Keystone and Conemaugh electric generating plants inWestern Pennsylvania, as well as in the transmission line that transports theplants’ output to the joint owners’ service territories. Our ownershipinterests in these plants are 20.99% in Keystone and 10.56% in Conemaugh. Theseownership interests represented a net investment of $183.1 million at December 31,2006 and $171.8 million at December 31, 2005. Each owner isresponsible for financing its proportionate share of the plants’ working funds.Working funds are used for operating expenses and capital expenditures.Operating expenses related to these plants are included in “Operating expenses”in our Consolidated Statements of Income. Capital costs related to these plantsare included in “Nonregulated property, plant and equipment” in ourConsolidated Balance Sheets.

The “Nonregulatedproperty, plant and equipment” in our Consolidated Balance Sheets includesnonregulated generation construction work in progress of $229.5 million at December 31,2006 and $228.8 million at December 31, 2005.

When we retireor dispose of property, plant and equipment, we remove the asset’s cost fromour Consolidated Balance Sheets. We charge this cost to accumulateddepreciation for assets that were depreciated under the group, straight-linemethod. This includes regulated property, plant and equipment and nonregulatedgenerating assets transferred from BGE to our merchant energy business. For allother assets, we remove the accumulated depreciation and amortization amountsfrom our Consolidated Balance Sheets and record any gain or loss in ourConsolidated Statements of Income.

The costs ofmaintenance and certain replacements are charged to “Operating expenses” in ourConsolidated Statements of Income as incurred.

Our oil and gasexploitation and production activities consist of working interests in gasproducing fields. We account for these activities under the successful effortsmethod of accounting. Acquisition, development, and exploitation costs arecapitalized as permitted by SFAS No. 19*.*Costs of drilling exploratory wells are initially capitalized and later chargedto expense if reserves are not discovered or deemed not to be commerciallyviable. Other exploratory costs are charged to expense when incurred.

Capitalizedexploratory well costs were $24.7 million at December 31, 2006 and$11.4 million at December 31, 2005, and do not include amounts thatwere capitalized and subsequently expensed within the same period. During 2006,there were $23.9 million of well costs capitalized at December 31, 2005that were reclassified to well, facilities, and equipment based on thedetermination of proved reserves. During 2005, there were $1.4 million ofwell costs capitalized at December 31, 2004 that were reclassified towell, facilities, and equipment based on the determination of proved reserves.

No exploratory well costs have been capitalized for a period greaterthan one year since the completion of drilling.

***Depreciationand Depletion Expense***

We compute depreciation for our generating, electric transmission anddistribution, and gas distribution facilities. We compute depletion for ourexploitation and production activities. Depreciation and depletion aredetermined using the following methods:

 ̈  thegroup straight-line method, approved by the Maryland PSC, applied to theaverage investment, adjusted for anticipated costs of removal less salvage, inclasses of depreciable property based on an average rate of approximately 3.5%per year for our regulated business,

 ̈  thegroup straight-line method using rates averaging approximately 2.5% per yearfor the fossil generating assets transferred from BGE to our merchant energybusiness and our nuclear generating assets,

 ̈  themodified units of production method (greater of straight-line method or unitsof production method) for fossil generating assets constructed afterderegulation that were not previously owned by BGE, or

 ̈  theunits-of-production method over the remaining life of the estimated provedreserves at the field level for acquisition costs and over the remaining lifeof proved developed reserves at the field level for development costs. The estimatesfor gas reserves are based on internal calculations.

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Other assets are depreciated primarily usingthe straight-line method and the following estimated useful lives:
| **Asset**                      | ** ** | **Estimated Useful Lives** |
|--------------------------------|------------|----------------------------|
| Building and improvements      |       | 5 – 50 years          |
| Office equipment and furniture |       | 3 – 20 years          |
| Transportation equipment       |       | 5 – 15 years          |
| Computer software              |       | 3 – 10 years          |

 

***AmortizationExpense***

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

***AccretionExpense***

SFAS No. 143,*Accounting for Asset Retirement Obligations,*provides the accounting requirements for recognizing an estimated liability forlegal obligations associated with the retirement of tangible long-lived assets.In the fourth quarter of 2005, we adopted FIN 47, *Accounting for Conditional Asset Retirement Obligations—anInterpretation of FASB Statement No. 143.* FIN 47 clarifies thatasset retirement obligations that are conditional upon a future event aresubject to the provisions of SFAS No. 143*.*Our conditional asset retirement obligations relate primarily to asbestosremoval at certain of our generating facilities. In 2005, we recorded an assetretirement obligation of $13.9 million for these facilities and recorded a$7.4 million after-tax charge to earnings as a cumulative effect of changein accounting principle.

At December 31,2006, $950.4 million of our total asset retirement obligation of $974.8million was associated with the decommissioning of our nuclear power plants—CalvertCliffs Nuclear Power Plant (Calvert Cliffs), Nine Mile Point Nuclear Station(Nine Mile Point) and R. E. Ginna Nuclear Power Plant (Ginna). The remainder ofour asset retirement obligations is associated with our other generatingfacilities and certain other long-lived assets. From time to time, we willperform studies to update our asset retirement obligations. We record aliability when we are able to reasonably estimate the fair value of any futurelegal obligations associated with retirement that have been incurred andcapitalize a corresponding amount as part of the book value of the relatedlong-lived assets.

The increase in the capitalized cost isincluded in determining depreciation expense over the estimated useful lives ofthese assets. Since the fair value of the asset retirement obligations isdetermined using a present value approach, accretion of the liability due tothe passage of time is recognized each period to “Accretion of asset retirementobligations” in our Consolidated Statements of Income until the settlement ofthe liability. We record a gain or loss when the liability is settled afterretirement for any difference between the accrued liability and actual costs.The change in our “Asset retirement obligations” liability during 2006 was asfollows:
| ** **                          | ** ** | ***(In millions)*** | ** ** |
|-------------------------------------|------------|--------------------------|------------|
| Liability at January 1, 2006   |       |                     | $          | 908.0 |   |   |
| Liabilities incurred                |       |                     | 3.4        |   |   |
| Liabilities settled                 |       |                     | (0.3       | ) |   |
| Accretion expense                   |       |                     | 67.6       |   |   |
| Revisions to cash flows             |       |                     | (2.4       | ) |   |
| Other                               |       |                     | (1.5       | ) |   |
| Liability at December 31, 2006 |       |                     | $          | 974.8 |   |   |

 

“Liabilities incurred” in the table above primarily reflect new assetretirement obligations recorded at our fossil generating facilities inMaryland. “Other” represents the asset retirement obligation associated withour gas-fired plants, which were sold in December 2006. At the time of thesale, the asset retirement obligation was transferred to the buyer of thegas-fired plants. We discuss the sale of the gas-fired plants in more detail in*Note 2*.

**Nuclear Fuel**

We amortize the cost of nuclear fuel, including the quarterly fees wepay to the Department of Energy for the future disposal of spent nuclear fuel,based on the energy produced over the life of the fuel. These fees are based onthe kilowatt-hours of electricity sold. We report the amortizationexpense for nuclear fuel in “Fuel and purchased energy expenses” in our ConsolidatedStatements of Income.

***NuclearDecommissioning***

Effective January 1,2003, we began to record decommissioning expense for Calvert Cliffs inaccordance with SFAS No. 143*.*The “Asset retirement obligations” liability associated with the decommissioningof Calvert Cliffs was $332.4 million at December 31, 2006 and$308.2 million at December 31, 2005. Our contributions to the nucleardecommissioning trust funds for Calvert Cliffs were $8.8 million for 2006,$17.6 million for 2005, and $22.0 million for 2004. Under theMaryland PSC’s order deregulating electric generation, BGE’s customers must paya total of $520 million in 1993 dollars, adjusted for inflation, todecommission Calvert Cliffs. BGE is collecting this amount on behalf of andpassing it to Calvert Cliffs. Calvert Cliffs is responsible for any differencebetween this amount and the actual costs to decommission the plant.

In 2006, BGEreceived approval from the Maryland PSC to continue annual customer collectionsof $18.7 million per year through December 31, 2016. BGE will be requiredto submit a filing to determine the level of customer contributions after December 31,2016.

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We began torecord decommissioning expense for Nine Mile Point in accordance with SFAS No. 143on January 1, 2003. The “Asset retirement obligations” liabilityassociated with the decommissioning was $408.1 million at December 31,2006 and $378.7 million at December 31, 2005. We determined that thedecommissioning trust funds established for Nine Mile Point are adequatelyfunded to cover the future costs to decommission the plant and as such, nocontributions were made to the trust funds during the years ended December 31,2006, 2005, and 2004.

Upon theclosing of the Ginna acquisition in 2004, the seller transferred$200.8 million in decommissioning funds. In return, we assumed all liabilityfor the costs to decommission the unit. We believe that this transfer will besufficient to cover the future costs to decommission the plant and as such, nocontributions were made to the trust funds during the years ended December 31,2006, 2005, and 2004. Effective June 2004, we began to recorddecommissioning expense for Ginna in accordance with SFAS No. 143. The “Assetretirement obligations” liability associated with the decommissioning was$209.9 million at December 31, 2006 and $196.6 million at December 31,2005.

In accordancewith Nuclear Regulatory Commission (NRC) regulations, we maintain externaldecommissioning trusts to fund the costs expected to be incurred todecommission Calvert Cliffs, Nine Mile Point, and Ginna. The NRC requiresowners to provide financial assurance that they will accumulate sufficientfunds to pay for the cost of nuclear decommissioning. The assets in the trustsare reported in “Nuclear decommissioning trust funds” in our ConsolidatedBalance Sheets. These amounts are legally restricted for funding the costs ofdecommissioning. We classify the investments in the nuclear decommissioningtrust funds as available-for-sale securities, and we report these investmentsat fair value in our Consolidated Balance Sheets as previously discussed inthis Note. Investments by nuclear decommissioning trust funds are guided by the“prudent man” investment principle. The funds are prohibited from investingdirectly in Constellation Energy or its affiliates and any other entity owninga nuclear power plant.

As the owner of Calvert Cliffs we, along with other domestic utilities,were required by the Energy Policy Act of 1992 to make contributions to a fundfor decommissioning and decontaminating the Department of Energy’s uraniumenrichment facilities. The contributions were paid by BGE over a 15 yearperiod ending in 2006. BGE amortizes the deferred costs of decommissioning anddecontaminating the Department of Energy’s uranium enrichment facilities. Theprevious owners retained the obligation for Nine Mile Point and Ginna.

**Capitalized Interest and Allowance for FundsUsed During Construction**

***CapitalizedInterest***

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

***Allowance forFunds Used During Construction (AFC)***

BGE financesits construction projects with borrowed funds and equity funds. BGE is allowedby the Maryland PSC to record the costs of these funds as part of the cost ofconstruction projects in its Consolidated Balance Sheets. BGE does this throughthe AFC, which it calculates using rates authorized by the Maryland PSC. BGEbills its customers for the AFC plus a return after the utility property isplaced in service.

The AFC rates are 9.4% for electric plant, 8.5% for gas plant, and 9.2%for common plant. BGE compounds AFC annually.

**Long-Term Debt**

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

When BGE incurs gains or losses on debt that it retires prior tomaturity, it amortizes those gains or losses over the remaining original lifeof the debt.

**Accounting Standards Issued**

*SFAS No. 157*

In September 2006, the FASB issued SFAS No. 157, *Fair Value Measurements*. SFAS No. 157 defines fairvalue, establishes a framework for measuring fair value, and expandsdisclosures for fair value measurements. SFAS No. 157 is effective for allfair value measurements beginning January 1, 2008. We are currentlyassessing the potential impact of SFAS No. 157. Based upon our initialassessment, we believe that SFAS No. 157 will affect the accountingfor derivatives, which is one of our critical accounting policies, in at leasttwo ways:

 ̈  We record mark-to-market energyassets net of a close-out valuation adjustment, a portion of which representsthe initial contract margin when we are unable to obtain observable marketprice information for similar contracts. As a result, we do not recognize gainsor losses in earnings at the inception of such contracts; instead, we recognizegains or losses in earnings as we realize cash flows under the contract or whenobservable market data becomes available. In certain instances, SFAS No. 157will require us to record mark-to-market energy assets at fair value withoutsuch a valuation adjustment, resulting in the potential for recognition ofgains or losses in earnings at the inception of new mark-to-market derivativecontracts executed after the effective date.

 ̈  We presently determine fairvalue for mark-to-market energy liabilities and risk management liabilities forwhich prices are not available from external sources by discounting theexpected cash flows from the contracts using a risk-free discount rate. We donot apply a credit-spread valuation adjustment to reflect our own credit riskin determining fair value for these liabilities. SFAS No. 157 willrequire us to record all liabilities measured at fair value including theeffect of the obligor’s credit risk. As a result, we will have to apply a credit-spreadadjustment in order to reflect our own credit risk in determining fair valuefor these liabilities, 

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which we expectwould result in a lower recorded fair value for these liabilities.

Because SFAS No. 157 applies broadly to all fair valuemeasurements, we have not completed our assessment of its requirements, theeffects of which could extend beyond the matters discussed on the previous page.In accordance with the statement’s provisions, we will record the initialeffects of applying SFAS No. 157 by adjusting opening retainedearnings as of the required January 1, 2008 adoption date for the effectof eliminating the close-out valuation adjustment for inception gains. The remaining impacts of adoption will be reflected inearnings in 2008. The ultimate impact of applying the provisions of SFAS No. 157could be material to our, or BGE’s, financial results.

***FIN 48***

In July 2006, the FASB issued Interpretation (FIN) No. 48, *Accounting for Uncertainty in Income Taxes*.FIN 48 provides guidance for the recognition and measurement of an entity’suncertain tax positions through the use of a “more-likely-than-not” threshold. Thisthreshold would be used to evaluate whether each tax position will be sustainedbased solely on its technical merits and assuming examination by a taxingauthority. FIN 48 must be applied to all tax positions beginning January 1,2007. Based on the analysis performed to date, we estimate the adoption ofFIN 48 will not have a material impact on our, or BGE’s, financialresults. As a result of pending implementation guidance, we are stillevaluating the impact of FIN 48, and therefore the actual impact of FIN 48 onour, or BGE’s, financial results could differ from the above estimate.

**Accounting Standards Adopted**

***SFAS No. 158***

In September 2006,the FASB issued SFAS No. 158, *Employers’ Accounting forDefined Benefit Pension and Other Postretirement Plans, an amendment of FASBStatements No. 87, 106 and 132(R)*. SFAS No. 158 requiresthe underfunded status of defined benefit postretirement plans to be recognizedas a liability in the balance sheets. Unrecognized actuarial losses or gains,unrecognized prior service costs, and unrecognized transition amounts arerecognized as part of accumulated other comprehensive income, net of tax.Subsequent changes in funded status are recognized in the year in which changesoccur through accumulated other comprehensive income. SFAS No. 158 waseffective for us on December 31, 2006.

Although weadopted SFAS No. 158 effective December 31, 2006, we were required toremeasure the additional minimum pension liability prior to calculating theimpact of adopting SFAS No. 158. As a result, we recorded a $75.6 millionafter-tax increase to accumulated other comprehensive income to reduce the additionalminimum pension liability at December 31, 2006. This reflected favorableasset returns and an increase in our discount rate assumption in 2006.

We recorded an after-tax decrease to accumulated other comprehensiveincome of $169.5 million at December 31, 2006 upon the adoption of SFAS No. 158.This reflected the requirement in SFAS No. 158 to begin reflecting thefunded status for postretirement benefit plans and to begin using the higherprojected benefit obligation measure to reflect pension plan funded status. Theadoption of SFAS No. 158 did not have any impact on BGE’s financialresults or our, or BGE’s, debt covenants. We discuss the additional minimumpension liability and the adoption of SFAS No. 158 in more detail in *Note 7*.

***FSP FIN 46R-6***

In April 2006, the FASB issued Staff Position (FSP) FIN 46R-6,*Determining the Variability to Be Consideredin Applying FASB Interpretation No. 46R.* FSP FIN 46R-6provides that, in applying FASB Interpretation No. 46R, *Consolidation of Variable Interest Entities anInterpretation of ARB No. 51,* the reporting enterprise shouldconsider the design of the entity, the nature of the entity’s risks, and thepurpose for which the entity was created. FSP FIN 46R-6 must be appliedprospectively to new or modified contracts beginning July 1, 2006. Theadoption of this FSP did not have a material impact on our, or BGE’s, financialresults.

***FSP FAS 115-1and FAS 124-1***

In November 2005, FASB Staff Position SFAS 115-1 andSFAS 124-1 (FSP FAS 115-1 and FAS 124-1), *The Meaning of Other-Than-Temporary Impairment andits Application to Certain Investments,* was issued to replace themeasurement and recognition criteria of EITF 03-1, *The Meaningof Other-Than-Temporary Impairment and its Application to Certain Investments*.FSP FAS 115-1 and FAS 124-1 references existing guidance inSFAS No. 115*,* SEC StaffAccounting Bulletin No. 59, *Accountingfor Noncurrent Marketable Equity Securities*, and APB No. 18. FSP FAS115-1 and FAS 124-1 requires an other-than-temporary analysis to becompleted each reporting period (i.e., every quarter) beginning after December 15,2005. The adoption of this standard did not have a material impact on our, orBGE’s, financial results.

***SAB 108***

In September 2006,the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108(SAB 108), *Considering the Effects of Prior Year Misstatementswhen Quantifying Misstatements in Current Year Financial Statements*.SAB 108 was issued in order to eliminate the diversity in practice surroundinghow public companies quantify financial statement misstatements.

SAB 108establishes an approach that requires quantification of financial statementmisstatements based on the effects of the misstatements on each financialstatement and the related financial statement disclosures. This model requiresquantification of errors based on both an income statement and balance sheetapproach. SAB 108 required public companies to initially apply its provisionsfor fiscal periods ending after November 15, 2006.

Theimplementation of SAB 108 did not have any effect on our financial results.

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**2** Other Events

**2006 Events**
| ** **                                                            | ** ** | **Pre-Tax**              | ** ** | **After-Tax** | ** ** |
|-----------------------------------------------------------------------|------------|--------------------------|------------|---------------|------------|
| ** **                                                            | ** ** | ***(In millions)*** | ** ** |
| Gain on sale of gas-fired plants                                      | ** ** |                     | **$**      | **73.8**      | ** ** |   |   | **$** | **47.1** | ** ** |   |
| Workforce reduction costs                                             | ** ** |                     | **(28.2**  | **)**         |       |   | **(17.0** | **)** |   |
| Merger-related costs                                                  | ** ** |                     | **(18.3**  | **)**         |       |   | **(5.7** | **)** |   |
| Gain on initial public offering of Constellation  Energy Partners LLC | ** ** |                     | **28.7**   | ** **    |       |   | **17.9** | ** ** |   |
| Income from discontinued operations                                   | ** ** |                     | ** ** | ** **    |       |   | ** ** | ** ** |   |
| High Desert                                                           | ** ** |                     | **294.1**  | ** **    |       |   | **186.9** | ** ** |   |
| International  investments                                            | ** ** |                     | **1.4**    | ** **    |       |   | **0.9** | ** ** |   |
| Total income from discontinued operations                             | ** ** |                     | **295.5**  | ** **    |       |   | **187.8** | ** ** |   |
| Total  other items                                                    | ** ** |                     | **$**      | **351.5**     | ** ** |   |   | **$** | **230.1** | ** ** |   |

 

***Sale ofGas-Fired Plants***

In December 2006, we completed the sale ofthe following natural gas-fired plants owned by our merchant energy business:
| **Facility**    | ** ** | **Capacity  (MW)** | ** ** | **Unit Type** | ** ** | **Location**   | ** ** |
|-----------------|------------|--------------------|------------|--------------------|------------|----------------|------------|
| High Desert     |       |               | 830        |               |       | Combined Cycle |       | California |   |
| Rio Nogales     |       |               | 800        |               |       | Combined Cycle |       | Texas |   |
| Holland         |       |               | 665        |               |       | Combined Cycle |       | Illinois |   |
| University Park |       |               | 300        |               |       | Peaking        |       | Illinois |   |
| Big Sandy       |       |               | 300        |               |       | Peaking        |       | West Virginia |   |
| Wolf Hills      |       |               | 250        |               |       | Peaking        |       | Virginia |   |

 

We sold these gas-fired plants for cash of $1.6 billion, which issubject to working capital adjustments, and recognized a pre-tax gain onthe sale of $259.0 million of which $73.8 million was included in “Gain onsale of gas-fired plants” and $185.2 million was included in “Income fromdiscontinued operations” in our Consolidated Statements of Income.

At the time ofthe agreement for sale, we evaluated these plants for classification asdiscontinued operations under SFAS No. 144. Discontinued operationsclassification only applies to assets held for sale that meet the definition ofa component of an entity. A component of an entity comprises operations andcash flows that can be clearly distinguished, operationally and for financialreporting purposes, from the rest of the entity.

High Desert metthe requirements to be classified as a discontinued operation because it had apower sales agreement for its full output, was determined to be a component ofConstellation Energy, and had separately identifiable cash flows. The tablebelow provides additional detail about the amounts recorded in “Income fromdiscontinued operations” related to our High Desert facility.

The remaining gas-fired plants were managed within our merchantbusiness as a group or on a portfolio basis because they have aggregated risks,were hedged as a group, and generated joint cash flows. These gas-fired plantsdo not meet the requirements to be classified as discontinued operations. Theresults of operations for these gas-fired plants, as well as the $73.8 millionpre-tax gain on sale, remain classified in continuing operations.

***InternationalInvestments***

In the fourthquarter of 2005, we completed the sale of Constellation Power InternationalInvestments, Ltd. (CPII). We recognized an after-tax gain of$0.9 million for the year ended December 31, 2006 due to theresolution of an outstanding contingency related to the sale. We discuss thedetails of the outstanding contingency later in this Note.

Presented in the table below are the amountsrelated to those discontinued operations that are included in “Income fromdiscontinued operations” in our Consolidated Statements of Income:

| ** **                                                   | ** ** | **High Desert**     | ** ** | **Oleander** | ** ** | **International Investments** | ** ** | **Total** | ** ** |
|--------------------------------------------------------------|------------|--------------------------|------------|--------------|------------|------------------------------------|------------|-----------|------------|
| ** **                                                   | ** ** | **2006**                 | ** ** | **2005**     | ** ** | **2004**                           | ** ** | **2006**  | ** ** | **2005** | ** ** | **2004** | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                   | ** ** | ***(In millions)*** | ** ** |
| Revenues                                                     | ** ** | **$**                    | **161.2**  |         | $          | 163.7                              |       | $         | 159.2      |   |   | **$** | **—** |   |   | $ | 14.7 |   | $ | 42.5 | ** ** | **$** | **—** |   | $ | 228.1 |   | $ | 219.7 | ** ** | **$** | **161.2** |   | $ | 406.5 |   | $ | 421.4 |   |
| Income before income  taxes                                  | ** ** | **108.9**                |       | 111.0        |       | 106.9                              |       |      | **—** |   |   | 8.5 |   | 20.5 | ** ** | **—** |   | 14.5 |   | 16.8 | ** ** | **108.9** |   | 134.0 |   | 144.2 |   |
| Net income                                                   | ** ** | **70.2**                 |       | 70.8         |       | 68.4                               |       |      | **—** |   |   | 5.3 |   | 12.6 | ** ** | **—** |   | 4.5 |   | 9.4 | ** ** | **70.2** |   | 80.6 |   | 90.4 |   |
| Pre-tax impairment  charge                                   |       | —                   |       | —       |       | —                             |       |      | **—** |   |   | (4.8 | ) | — | ** ** | **—** |   | — |   | — |   | — |   | (4.8 | ) | — |   |
| After-tax  impairment charge                                 |       | —                   |       | —       |       | —                             |       |      | **—** |   |   | (3.0 | ) | — | ** ** | **—** |   | — |   | — |   | — |   | (3.0 | ) | — |   |
| Pre-tax gain on  sale                                        | ** ** | **185.2**                |       | —       |       | —                             |       |      | **—** |   |   | 1.2 |   | — | ** ** | **1.4** |   | 25.6 |   | — | ** ** | **186.6** |   | 26.8 |   | — |   |
| After-tax gain on  sale                                      | ** ** | **116.7**                |       | —       |       | —                             |       |      | **—** |   |   | 0.7 |   | — | ** ** | **0.9** |   | 16.1 |   | — | ** ** | **117.6** |   | 16.8 |   | — |   |
| Income from discontinued  operations, net of taxes | ** ** | **186.9**                |       | 70.8         |       | 68.4                               |       |      | **—** |   |   | 3.0 |   | 12.6 | ** ** | **0.9** |   | 20.6 |   | 9.4 | ** ** | **187.8** |   | 94.4 |   | 90.4 |   |
|                                                              |            |                          |            |              |            |                                    |            |           |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

*Werecognized a pre-tax loss from discontinued operations of $(75.6) million,before income taxes of $(26.5) million from the sale of our Hawaiian Geothermalfacility in 2004. We discuss the sale of this facility later in this Note.*

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***Workforce Reduction Costs***

In March 2006, we approveda restructuring of the workforce at our Ginna nuclear facility. In connectionwith this restructuring, 32 employees were terminated. During the quarter endedMarch 31, 2006, we recognized costs of $2.2 million pre-tax relatedto recording a liability for severance and other benefits under our existingbenefit programs.

We completed this workforcereduction effort in 2006. As a result, no involuntary severance liability wasrecorded at December 31, 2006.

In July 2006, we announceda planned restructuring of the workforce at our Nine Mile Point nuclearfacility. We recognized costs during the quarter ended September 30, 2006of $15.1 million pre-tax related to the elimination of 126 positions associatedwith this restructuring. We also initiated a restructuring of the workforce atour Calvert Cliffs nuclear facility during the third quarter of 2006 and werecognized costs of $2.9 million pre-tax related to the elimination of 30 positionsassociated with this restructuring.

In addition, weincurred a pre-tax settlement charge of $12.7 million in accordance withStatement of Financial Accounting Standards (SFAS) No. 88, *Employers’ Accounting for Settlements and Curtailments of DefinedBenefit Pension Plans and for Termination Benefits*. This charge reflects recognition of the portion ofdeferred actuarial gains and losses associated with employees who wereterminated as part of the restructuring or retired in 2006 and who elected toreceive their pension benefit in the form of a lump-sum payment. In accordancewith SFAS No. 88, a settlement charge must be recognized whenlump-sum payments exceed annual pension plan service and interest cost. Thetotal SFAS No. 88 settlement charge incurred in 2006 includes a pre-taxcharge of $8.0 million as a result of the Nine Mile Point restructuring. Wediscuss the settlement charges that we recorded during 2006 in *Note 7*.

The following table summarizes the status of the involuntary severanceliability for Nine Mile Point and Calvert Cliffs at December 31, 2006:
| ** **                                                 | ** ** | ***(In millions)*** | ** ** |
|------------------------------------------------------------|------------|--------------------------|------------|
| Initial severance liability balance                        |       |                     | $          | 19.6 |   |   |
| Amounts recorded as pension and postretirement liabilities |       |                     | (7.3       | ) |   |
| Net cash severance liability                               |       |                     | 12.3       |   |   |
| Cash severance payments                                    |       |                     | (3.2       | ) |   |
| Other                                                      |       |                     | —     |   |   |
| Severance liability balance at December 31, 2006      |       |                     | $          | 9.1 |   |   |

 

*The severance liability above includes $1.6million of costs that the joint owner of Nine Mile Point Unit 2 reimbursed  us.*

***Merger-Related costs***

We incurred costs during 2006related to the proposed merger with FPL Group. The merger was terminated in October2006. These costs totaled $18.3 million pre-tax for 2006. In addition,during 2006 we recognized tax benefits of $5.3 million on merger costsincurred in 2005 that were not considered deductible for income tax purposesuntil the termination of the merger in 2006. Our total pre-tax merger-relatedcosts were $35.3 million.

***Initial Public Offering of ConstellationEnergy Partners LLC***

In November 2006, Constellation Energy Partners LLC (CEP), alimited liability company formed by Constellation Energy, completed an initialpublic offering of 5.2 million common units at $21 per unit. The initial publicoffering resulted in cash proceeds of $101.3 million, after expenses associatedwith the offering, for Constellation Energy.

We continue to own approximately54% of CEP and as a result, we continue to consolidate CEP. As a result of theinitial public offering of CEP, we recognized a pre-tax gain of $28.7 million,or $17.9 million after recording deferred taxes on the gain.

**2005 Events**
| ** **                                | ** ** | **Pre-Tax**              | ** ** | **After-Tax** | ** ** |
|-------------------------------------------|------------|--------------------------|------------|---------------|------------|
| ** **                                | ** ** | ***(In millions)*** | ** ** |
| Merger-related costs                      | ** ** |                     | $          | (17.0         | )          |   |   | $ | (15.6 | **)** |   |
| Workforce reduction costs                 | ** ** |                     | (4.4       | )             |       |   | (2.6 | **)** |   |
| Income from discontinued operations       | ** ** |                     |       |          |       |   |   | ** ** |   |
| High Desert                               | ** ** |                     | 111.0      |          |       |   | 70.8 | ** ** |   |
| International investments                 | ** ** |                     | 40.1       |          |       |   | 20.6 | ** ** |   |
| Oleander                                  | ** ** |                     | 4.9        |          |       |   | 3.0 | ** ** |   |
| Total income from discontinued operations | ** ** |                     | 156.0      |          |       |   | 94.4 | ** ** |   |
| Total other items                         | ** ** |                     | $          | 134.6         |       |   |   | $ | 76.2 | ** ** |   |

 

*“Incomefrom discontinued operations” reflects the reclassification of earnings fromour High Desert facility as required by SFAS No. 144.*

***Merger-RelatedCosts***

We incurred external costs associated with the execution of theagreement relating to our proposed merger with FPL Group. We discuss theterminated merger in more detail in *Note 15.*

***Workforce Reduction Costs***

As a result of the workforce reduction efforts initiated in 2004, in2005 we were required to record a pre-tax settlement charge in our ConsolidatedStatements of Income of $4.4 million for one of our qualified pensionplans under SFAS No. 88.

In 2005, we completed the 2004 workforcereduction effort. As a result, no involuntary severance liability was recordedat December 31, 2005.

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***Discontinued Operations***

*Oleander*

In March 2005, we reached an agreement in principle to sell ourOleander generating facility, a four-unit peaking plant located in Florida. Ourmerchant energy business classified Oleander as held for sale and performed animpairment test under SFAS No. 144 as of March 31, 2005. Theimpairment test indicated that the carrying value of the plant was higher thanits fair value less costs to sell, and therefore in March 2005 we recordedan impairment charge of $4.8 million pre-tax as part of discontinuedoperations.

In June 2005, we completed the sale of this facility for$217.6 million, and recognized a pre-tax gain on the sale of$1.2 million as part of discontinued operations.

*International Investments*

In October 2005, we sold CPII. CPII held our other nonregulatedinternational investments, which represented an interest in a Panamanianelectric distribution company and an investment in a fund that holds interestsin two South American energy projects. We received cash of $71.8 millionand recognized a pre-tax gain of approximately $25.6 million, or$16.1 million after-tax. An additional $3.6 million of the salesprice was contingent upon the collection of certain receivables by March 31,2006. At December 31, 2005, we recognized approximately $2.2 millionof this amount based on cash collections, which was included in the$25.6 million pre-tax gain. We recognized the remaining $1.4 millionof contingent proceeds in 2006 once realization was assured beyond a reasonabledoubt.

**2004 Events**
| ** **                                      | ** ** | **Pre-Tax**              | ** ** | **After-Tax** | ** ** |
|-------------------------------------------------|------------|--------------------------|------------|---------------|------------|
| ** **                                      | ** ** | ***(In millions)*** | ** ** |
| Workforce reduction costs                       |       |                     | $          | (9.7          | )          |   |   | $ | (5.9 | ) |   |
| Recognition of 2003 synthetic  fuel tax credits |       |                     | —     |          |       |   | 35.9 |   |   |
| (Loss) income from discontinued  operations     |       |                     |       |          |       |   |   |   |   |
| Hawaiian geothermal facility                    |       |                     | (75.6      | )             |       |   | (49.1 | ) |   |
| High Desert                                     |       |                     | 106.9      |          |       |   | 68.4 |   |   |
| International investments                       |       |                     | 16.8       |          |       |   | 9.4 |   |   |
| Oleander                                        |       |                     | 20.5       |          |       |   | 12.6 |   |   |
| Total income from discontinued  operations      |       |                     | 68.6       |          |       |   | 41.3 |   |   |
| Total other items                               |       |                     | $          | 58.9          |       |   |   | $ | 71.3 |   |   |

 

*“Incomefrom discontinued operations” reflects the reclassification of earnings fromour High Desert facility, the Oleander facility, and our international investmentsas required by SFAS No. 144.*

***WorkforceReduction Costs***

In the fourth quarter of 2004, we approved a restructuring of the workforces of the Nine Mile Point and Calvert Cliffs nuclear generating stationsthat was effective in January 2005. In connection with this restructuring,approximately 108 employees received severance and other benefits under ourexisting benefit programs. At December 31, 2004, we accrued the estimatedtotal cost of this reduction in workforce of $9.7 million pre-tax, or$5.9 million after-tax, in accordance with applicable accountingrequirements.

***Synthetic FuelTax Credits***

In 2003, we purchased a 99% ownership in a South Carolina facility thatproduces synthetic fuel. We did not recognize in our Consolidated Statements ofIncome the tax benefit of $35.9 million for credits claimed on our SouthCarolina facility in 2003 pending receipt of a favorable private letter rulingfrom the Internal Revenue Service (IRS). In April 2004, we received afavorable private letter ruling. We believe receipt of the private letterruling provided assurance that it is highly probable that the credits will besustained. Therefore, we recognized the tax benefit of $35.9 million inour Consolidated Statements of Income in 2004. We discuss the synthetic fueltax credits in more detail in *Note 10.*

***DiscontinuedOperations***

*GeothermalFacility*

In March 2004,management committed to a plan to sell our geothermal generating facility inHawaii that met the “held for sale” criteria under SFAS No. 144*.* Under SFAS No. 144, we recordassets and liabilities held for sale at the lesser of the carrying amount orfair value less cost to sell.

The fair valueof the facility as of March 31, 2004, based on the bids underconsideration, was below carrying value. Therefore, we recorded a$71.6 million pre-tax, or $47.3 million after-tax, impairment chargeduring the first quarter of 2004. We reported the after-tax impairment chargeas a component of “Loss from discontinued operations” in our ConsolidatedStatements of Income. Additionally, we recognized $1.5 million pre-tax, or$1.0 million after-tax, of earnings from the facility for the quarterended March 31, 2004 as a component of “Loss from discontinued operations.”

In June 2004,we completed the sale of the facility. Based on the final sales price and othercosts incurred over the remainder of the year, we recognized an additional lossof $5.5 million pre-tax, or $2.8 million after-tax. The sale of thisfacility was reflected in our merchant energy business reportable segment.

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**3** Informationby Operating Segment

Our reportable operatingsegments are—Merchant Energy, Regulated Electric, and Regulated Gas:

 ̈  Ourmerchant energy business is nonregulated and includes:

– full requirements load-serving sales ofenergy and capacity to utilities, cooperatives, and commercial, industrial, andgovernmental customers,

– structured transactions and risk managementservices for various customers (including hedging of output from generatingfacilities and fuel costs),

– deployment of risk capital throughportfolio management and trading activities,

– gas retail energy products and services tocommercial, industrial, and governmental customers,

– fossil, nuclear, and interests inhydroelectric generating facilities and qualifying facilities, fuel processingfacilities, and power projects in the United States,

– upstream (exploration and production) anddownstream (transportation and storage) natural gas operations,

– coal sourcing services for the variable orfixed supply needs of global customers, and

– generation operations and maintenanceservices.

 ̈  Ourregulated electric business purchases, transmits, distributes, and sells electricityin Central Maryland.

 ̈  Ourregulated gas business purchases, transports, and sells natural gas in CentralMaryland.

Our remainingnonregulated businesses:

 ̈  design,construct, and operate heating, cooling, and cogeneration facilities forcommercial, industrial, and governmental customers throughout North America,and

 ̈  providehome improvements, service electric and gas appliances, service heating, airconditioning, plumbing, electrical, and indoor air quality systems, and providenatural gas marketing to residential customers in Central Maryland.

During 2006, wesold six of our gas-fired facilities. In addition, we own several investmentsthat we do not consider to be core operations. These include financialinvestments and real estate projects. During 2005, we sold our othernonregulated international investments. We discuss the sales of our gas-firedplants and our international investments in more detail in *Note 2*.

Our MerchantEnergy, Regulated Electric, and Regulated Gas reportable segments are strategicbusinesses based principally upon regulations, products, and services thatrequire different technology and marketing strategies. We evaluate theperformance of these segments based on net income. We account for intersegmentrevenues using market prices. We present a summary of information by operatingsegment on the next page.

 

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| ** **                                              | ** ** | **Reportable  Segments**       | ** **   | ** **                        | ** **  | ** **                   | ** **  | ** **                          | ** **  |
|---------------------------------------------------------|------------|--------------------------------|--------------|-----------------------------------|-------------|------------------------------|-------------|-------------------------------------|-------------|
| ** **

** **                                  | ** ** | **Merchant  Energy  Business** | ** **   | **Regulated  Electric  Business** | ** **  | **Regulated  Gas  Business** | ** **  | **Other  Nonregulated  Businesses** | ** **  | **Eliminations** | ** ** | **Consolidated** | ** ** |
| ** **                                              | ** ** | ***(In millions)***       | ** **   |
| **2006**                                                |       |                           |         |                              |        |                         |        |                                |        |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Unaffiliated revenues                                   | ** ** | **$**                          | **16,048.2** | ** **                        | ** **  | **$**                        | **2,115.9** |                                | ** **  | ** ** | **$** | **890.0** |   | ** ** | ** ** | **$** | **230.8** | ** ** | ** ** | ** ** | **$** | **—** | ** ** | ** ** | ** ** | **$** | **19,284.9** |   |   |
| Intersegment revenues                                   | ** ** | **1,118.0**                    | ** **   | ** **                        | **—**  |                         | ** **  | ** **                          | **9.5**     |   | ** ** | ** ** | **0.2** | ** ** | ** ** | ** ** | **(1,127.7** | **)** | ** ** | ** ** | **—** |   |   |
| Total revenues                                          | ** ** | **17,166.2**                   | ** **   | ** **                        | **2,115.9** |                         | ** **  | ** **                          | **899.5**   |   | ** ** | ** ** | **231.0** | ** ** | ** ** | ** ** | **(1,127.7** | **)** | ** ** | ** ** | **19,284.9** |   |   |
| Depreciation, depletion,  and amortization              | ** ** | **258.7**                      | ** **   | ** **                        | **181.5**   |                         | ** **  | ** **                          | **46.0**    |   | ** ** | ** ** | **37.7** | ** ** | ** ** | ** ** | **—** | ** ** | ** ** | ** ** | **523.9** |   |   |
| Fixed charges                                           | ** ** | **191.7**                      | ** **   | ** **                        | **86.9**    |                         | ** **  | ** **                          | **28.9**    |   | ** ** | ** ** | **10.5** | ** ** | ** ** | ** ** | **10.7** | ** ** | ** ** | ** ** | **328.7** |   |   |
| Income tax expense  (benefit)                           | ** ** | **250.2**                      | ** **   | ** **                        | **78.0**    |                         | ** **  | ** **                          | **27.0**    |   | ** ** | ** ** | **(4.2** | **)** | ** ** | ** ** | **—** | ** ** | ** ** | ** ** | **351.0** |   |   |
| Income from discontinued  operations                    | ** ** | **186.9**                      | ** **   | ** **                        | **—**  |                         | ** **  | ** **                          | **—**  |   | ** ** | ** ** | **0.9** | ** ** | ** ** | ** ** | **—** | ** ** | ** ** | ** ** | **187.8** |   |   |
| Net income (a)                                          | ** ** | **767.0**                      | ** **   | ** **                        | **120.2**   |                         | ** **  | ** **                          | **37.0**    |   | ** ** | ** ** | **12.2** |   |   |   | — | ** ** | ** ** | ** ** | **936.4** |   |   |
| Segment assets                                          | ** ** | **16,387.3**                   | ** **   | ** **                        | **3,783.2** |                         | ** **  | ** **                          | **1,252.8** |   | ** ** | ** ** | **887.8** | ** ** | ** ** | ** ** | **(509.5** | **)** | ** ** | ** ** | **21,801.6** |   |   |
| Capital expenditures                                    | ** ** | **768.0**                      | ** **   | ** **                        | **297.0**   |                         | ** **  | ** **                          | **63.0**    |   | ** ** | ** ** | **21.0** | ** ** | ** ** | ** ** | **—** | ** ** | ** ** | ** ** | **1,149.0** |   |   |
| **2005**                                                |       |                           |         |                              |        |                         |        |                                |        |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Unaffiliated revenues                                   |       | $                              | 13,763.1     |                              |        | $                            | 2,036.5     |                                |        |   | $ | 961.7 |   |   |   | $ | 207.0 |   |   |   | $ | — |   |   |   | $ | 16,968.3 |   |   |
| Intersegment revenues                                   |       | 859.3                          |         |                              | —      |                         |        |                                | 11.1        |   |   |   | — |   |   |   | (870.4 | ) |   |   | — |   |   |
| Total revenues                                          |       | 14,622.4                       |         |                              | 2,036.5     |                         |        |                                | 972.8       |   |   |   | 207.0 |   |   |   | (870.4 | ) |   |   | 16,968.3 |   |   |
| Depreciation, depletion,  and amortization              |       | 250.4                          |         |                              | 185.8       |                         |        |                                | 46.6        |   |   |   | 40.2 |   |   |   | — |   |   |   | 523.0 |   |   |
| Fixed charges                                           |       | 178.0                          |         |                              | 80.3        |                         |        |                                | 26.4        |   |   |   | 10.0 |   |   |   | 15.5 |   |   |   | 310.2 |   |   |
| Income tax expense (benefit)                            |       | 41.7                           |         |                              | 101.2       |                         |        |                                | 21.2        |   |   |   | (0.2 | ) |   |   | — |   |   |   | 163.9 |   |   |
| Income from discontinued  operations                    |       | 73.8                           |         |                              | —      |                         |        |                                | —      |   |   |   | 20.6 |   |   |   | — |   |   |   | 94.4 |   |   |
| Cumulative effects of  changes in accounting principles |       | (7.4                           | )            |                              | —      |                         |        |                                | —      |   |   |   | 0.2 |   |   |   | — |   |   |   | (7.2 | ) |   |
| Net income (b)                                          |       | 425.8                          |         |                              | 149.4       |                         |        |                                | 26.7        |   |   |   | 21.2 |   |   |   | — |   |   |   | 623.1 |   |   |
| Segment assets                                          |       | 16,620.4                       |         |                              | 3,424.4     |                         |        |                                | 1,222.5     |   |   |   | 476.1 |   |   |   | (269.5 | ) |   |   | 21,473.9 |   |   |
| Capital expenditures                                    |       | 709.0                          |         |                              | 241.0       |                         |        |                                | 50.0        |   |   |   | 32.0 |   |   |   | — |   |   |   | 1,032.0 |   |   |
| **2004**                                                | ** ** | ** **                     | ** **   | ** **                        | ** **  |                         | ** **  | ** **                          | ** **  |   | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |   |   |
| Unaffiliated revenues                                   |       | $                              | 9,203.7      |                              |        | $                            | 1,967.6     |                                |        |   | $ | 755.0 |   |   |   | $ | 200.9 |   |   |   | $ | — |   |   |   | $ | 12,127.2 |   |   |
| Intersegment revenues                                   |       | 984.6                          |         |                              | 0.1         |                         |        |                                | 2.0         |   |   |   | 0.2 |   |   |   | (986.9 | ) |   |   | — |   |   |
| Total revenues                                          |       | 10,188.3                       |         |                              | 1,967.7     |                         |        |                                | 757.0       |   |   |   | 201.1 |   |   |   | (986.9 | ) |   |   | 12,127.2 |   |   |
| Depreciation and  amortization                          |       | 221.9                          |         |                              | 194.2       |                         |        |                                | 48.1        |   |   |   | 24.2 |   |   |   | — |   |   |   | 488.4 |   |   |
| Fixed charges                                           |       | 196.2                          |         |                              | 80.3        |                         |        |                                | 29.1        |   |   |   | 15.4 |   |   |   | 5.8 |   |   |   | 326.8 |   |   |
| Income tax expense  (benefit)                           |       | 22.8                           |         |                              | 86.8        |                         |        |                                | 15.9        |   |   |   | (7.1 | ) |   |   | — |   |   |   | 118.4 |   |   |
| Income from discontinued  operations                    |       | 31.9                           |         |                              | —      |                         |        |                                | —      |   |   |   | 9.4 |   |   |   | — |   |   |   | 41.3 |   |   |
| Net income (loss) (c)                                   |       | 389.9                          |         |                              | 131.1       |                         |        |                                | 22.2        |   |   |   | (3.5 | ) |   |   | — |   |   |   | 539.7 |   |   |
| Segment assets                                          |       | 12,395.6                       |         |                              | 3,402.2     |                         |        |                                | 1,163.4     |   |   |   | 675.7 |   |   |   | (289.8 | ) |   |   | 17,347.1 |   |   |
| Capital expenditures                                    |       | 455.0                          |         |                              | 209.0       |                         |        |                                | 56.0        |   |   |   | 42.0 |   |   |   | — |   |   |   | 762.0 |   |   |

 

*Certain prior-year amounts have beenreclassified to conform with the current year’s presentation. Thereclassifications**primarilyrelate to operations that have been classified as discontinued operations inthe current year.*

*(a)**             Ourmerchant energy business recognized an after-tax gain of $47.1 million on saleof gas-fired plants and an after-tax gain of $17.9 million on the initialpublic offering of Constellation Energy Partners LLC as discussed in moredetail in Note 2. Our merchant energy business, our regulated electricbusiness, our regulated gas business, and our other nonregulated businessesrecognized after-tax charges of $21.3 million, $0.8 million, $0.4 million, and$0.2 million for merger-related costs and workforce reduction costs asdescribed in more detail in Note 2.*

*(b)**             Ourmerchant energy business, our regulated electric business, our regulated gasbusiness, and our other nonregulated businesses recognized after-tax charges of$13.0 million, $3.7 million, $1.3 million, and $0.2 millionfor merger-related  costs andworkforce reduction costs as described in more detail in Note 2.*

*(c)**               Ourmerchant energy business recognized after-tax income of $30.0 million, forrecognition of 2003 synthetic fuel tax credits and workforce reduction costs asdescribed in more detail in Note 2.*

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**4**Investments

**Investments in Qualifying Facilities and Power Projects**

Our merchantenergy business holds up to a 50% voting interest in 24 operating domesticenergy projects that consist of electric generation, fuel processing, or fuelhandling facilities. Of these 24 projects, 17 are “qualifying facilities” thatreceive certain exemptions and pricing under the Public Utility RegulatoryPolicies Act of 1978 based on the facilities’ energy source or the use of acogeneration process.

Investments in qualifying facilities anddomestic power projects held by our merchant energy business consist of thefollowing:
| ***At December 31,*** | ** ** | **2006**                 | ** ** | **2005** | ** ** |
|---------------------------------|------------|--------------------------|------------|----------|------------|
| ** **                      | ** ** | ***(In millions)*** | ** ** |
| Coal                            | ** ** | **$**                    | **125.7**  |     | $          | 127.8 |   |
| Hydroelectric                   | ** ** | **55.1**                 |       | 55.9     |       |
| Geothermal                      | ** ** | **40.5**                 |       | 43.7     |       |
| Biomass                         | ** ** | **46.6**                 |       | 48.0     |       |
| Fuel  Processing                | ** ** | **33.7**                 |       | 23.8     |       |
| Solar                           | ** ** | **7.0**                  |       | 7.0      |       |
| Total                           | ** ** | **$**                    | **308.6**  |     | $          | 306.2 |   |

 

Investments in qualifying facilities and domestic power projects wereaccounted for under the following methods:
| ***At December 31,*** | ** ** | **2006**                 | ** ** | **2005** | ** ** |
|---------------------------------|------------|--------------------------|------------|----------|------------|
| ** **                      | ** ** | ***(In millions)*** | ** ** |
| Equity method                   | ** ** | **$**                    | **301.6**  |     | $          | 299.2 |   |
| Cost method                     | ** ** | **7.0**                  |       | 7.0      |       |
| Total power projects            | ** ** | **$**                    | **308.6**  |     | $          | 306.2 |   |

 

Our percentagevoting interest in qualifying facilities and domestic power projects accountedfor under the equity method ranges from 16% to 50%. Equity in earnings of thesepower projects was $13.8 million in 2006, $3.6 million in 2005, and$18.0 million in 2004.

Our power projects include investments of $220.5 million in 2006 and$228.6 million in 2005 that sell electricity in California under powerpurchase agreements.

**Investments Classified asAvailable-for-Sale**

We classify thefollowing investments as available-for-sale:

 ̈  nucleardecommissioning trust funds,

 ̈  marketableequity securities, and

 ̈  trustassets securing certain executive benefits.

This means wedo not expect to hold them to maturity, and we do not consider them tradingsecurities.

We show the fair values, gross unrealizedgains and losses, and amortized cost basis for all of our available-for-salesecurities, in the following tables. We use specific identification todetermine cost in computing realized gains and losses.
| **At December 31, 2006** | ** ** | **Amortized  Cost Basis** | ** ** | **Unrealized  Gains** | ** ** | **Unrealized  Losses** | ** ** | **Fair  Value** | ** ** |
|-----------------------------------------|------------|--------------------------------|------------|-----------------------|------------|------------------------|------------|-----------------|------------|
| ** **                              | ** ** | ***(In millions)***       | ** ** |
| Marketable  equity securities           | ** ** |                           | **$**      | **811.0**             | ** ** |                   |       | **$**           | **221.1**  | ** ** |   |   | **$** | **(3.3** | **)** |   | **$** | **1,028.8** | ** ** |
| Corporate debt and U.S.  treasuries     | ** ** |                           | **160.1**  | ** **            |       |                   | **1.9**    | ** **      |       |   | **(0.3** | **)** |   | **161.7** | ** ** |
| State municipal bonds                   | ** ** |                           | **68.1**   | ** **            |       |                   | **5.4**    | ** **      |       |   | **(0.2** | **)** |   | **73.3** | ** ** |
| Totals                                  | ** ** |                           | **$**      | **1,039.2**           | ** ** |                   |       | **$**           | **228.4**  | ** ** |   |   | **$** | **(3.8** | **)** |   | **$** | **1,263.8** | ** ** |

 
| **At December 31, 2005**  | ** ** | **Amortized  Cost Basis** | ** ** | **Unrealized  Gains** | ** ** | **Unrealized  Losses** | ** ** | **Fair  Value** | ** ** |
|------------------------------------------|------------|--------------------------------|------------|-----------------------|------------|------------------------|------------|-----------------|------------|
| ** **                               | ** ** | ***(In millions)***       | ** ** |
| Marketable equity  securities            |       |                           | $          | 804.4                 |       |                   |       | $               | 112.7      |   |   |   | $ | (3.8 | ) |   | $ | 913.3 |   |
| Corporate debt and  U.S. treasuries |       |                           | 114.8      |                  |       |                   | 0.2        |            |       |   | (1.4 | ) |   | 113.6 |   |
| State municipal bonds                    |       |                           | 107.1      |                  |       |                   | 2.8        |            |       |   | (0.8 | ) |   | 109.1 |   |
| Totals                                   |       |                           | $          | 1,026.3               |       |                   |       | $               | 115.7      |   |   |   | $ | (6.0 | ) |   | $ | 1,136.0 |   |

 

In addition tothe above securities, the nuclear decommissioning trust funds included $24.1million at December 31, 2006 and $12.2 million at December 31,2005 of cash and cash equivalents.

The precedingtables include $206.1 million in 2006 of net unrealized gains and$110.3 million in 2005 of net unrealized gains associated with the nucleardecommissioning trust funds that are reflected as a change in the nucleardecommissioning trust funds in our Consolidated Balance Sheets.

We have unrealized losses relating to certainavailable-for-sale investments included in our decommissioning trust funds. Webelieve these losses are temporary in nature and expect the investments torecover their value in the future. We show the fair values and unrealizedlosses of our investments that were in a loss position at December 31,2006 and 2005 in the tables below.
| ***At December 31, 2006*** | ** **   | ** **                         | ** ** | ** **                       | ** ** | ** **      | ** ** | ** **             | ** ** |
|-------------------------------------------|--------------|------------------------------------|------------|----------------------------------|------------|-----------------|------------|------------------------|------------|
| ** **                                | ** **   | **Less than  12 months** | ** ** | **12 months or  more** | ** ** | **Total**       | ** ** |
| **Description of  Securities**       | ** **   | **Fair  Value**                    | ** ** | **Unrealized  Losses**           | ** ** | **Fair  Value** | ** ** | **Unrealized  Losses** | ** ** | **Fair  Value** | ** ** | **Unrealized  Losses** | ** ** |
| ** **                                | *** *** | ***(In millions)***           | ** ** |
| Marketable equity securities              | ** **   | **$**                              | **9.5**    | ** **                       |       | **$**           | **(0.8**   | **)**                  |       | **$** | **12.4** | ** ** |   | **$** | **(1.7** | **)** |   | **$** | **21.9** | ** ** |   | **$** | **(2.5** | **)** |   |
| Corporate debt and U.S. treasuries        | ** **   | **10.3**                           |       |                             | —     | ** **      |       | **23.7**               | ** ** |   | **(0.3** | **)** |   | **34.0** | ** ** |   | **(0.3** | **)** |   |
| State municipal bonds                     | ** **   | **4.8**                            |       |                             | —     | ** **      |       | **14.0**               | ** ** |   | **(0.2** | **)** |   | **18.8** | ** ** |   | **(0.2** | **)** |   |
| Total temporarily impaired securities     | ** **   | **$**                              | **24.6**   | ** **                       |       | **$**           | **(0.8**   | **)**                  |       | **$** | **50.1** | ** ** |   | **$** | **(2.2** | **)** |   | **$** | **74.7** | ** ** |   | **$** | **(3.0** | **)** |   |

 

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| ***At December 31, 2005*** | ** **   | ** **                         | ** ** | ** **                       | ** ** | ** **      | ** ** | ** **             | ** ** |
|-------------------------------------------|--------------|------------------------------------|------------|----------------------------------|------------|-----------------|------------|------------------------|------------|
| ** **                                | ** **   | **Less than  12 months** | ** ** | **12 months or  more** | ** ** | **Total**       | ** ** |
| **Description of  Securities**       | ** **   | **Fair  Value**                    | ** ** | **Unrealized  Losses**           | ** ** | **Fair  Value** | ** ** | **Unrealized  Losses** | ** ** | **Fair  Value** | ** ** | **Unrealized  Losses** | ** ** |
| ** **                                | *** *** | ***(In millions)***           | ** ** |
| Marketable equity securities              |         | $                                  | 22.3       |                             |       | $               | (2.9       | )                      |       | $ | 2.3 |   |   | $ | (0.3 | ) |   | $ | 24.6 |   |   | $ | (3.2 | ) |   |
| Corporate debt and U.S. treasuries        |         | 71.8                               |       |                             | (1.1       | )               |       | 11.8                   |       |   | (0.3 | ) |   | 83.6 |   |   | (1.4 | ) |   |
| State municipal bonds                     |         | 46.0                               |       |                             | (0.6       | )               |       | 11.8                   |       |   | (0.2 | ) |   | 57.8 |   |   | (0.8 | ) |   |
| Total temporarily impaired securities     |         | $                                  | 140.1      |                             |       | $               | (4.6       | )                      |       | $ | 25.9 |   |   | $ | (0.8 | ) |   | $ | 166.0 |   |   | $ | (5.4 | ) |   |

 

Gross and net realized gains and losses on available-for-salesecurities were as follows:
| ** **                  | ** ** | **2006**                 | ** ** | **2005** | ** ** | **2004** | ** ** |
|-----------------------------|------------|--------------------------|------------|----------|------------|----------|------------|
| ** **                  | ** ** | ***(In millions)*** | ** ** |
| Gross realized gains        | ** ** | **$**                    | **13.3**   |     | $          | 12.3     |       | $ | 4.1 |   |
| Gross realized losses       | ** ** | **(13.0**                | **)**      | (9.3     | )          | (7.7     | )          |
| Net realized gains (losses) | ** ** | **$**                    | **0.3**    |     | $          | 3.0      |       | $ | (3.6 | ) |

 

Gross realizedlosses for 2004 include a $4.5 million pre-tax impairment charge werecognized on a nuclear decommissioning trust fund investment that we believedrepresented an other than temporary decline in value.

The corporate debt securities, U.S. Government agency obligations, andstate municipal bonds mature on the following schedule:
| ***At December 31, 2006*** | ** ** | ** **               | ** ** |
|-------------------------------------------|------------|--------------------------|------------|
| ** **                                | ** ** | ***(In millions)*** | ** ** |
| Less than 1 year                          |       |                     | $          | 7.6 |   |   |
| 1-5 years                                 |       |                     | 74.9       |   |   |
| 5-10 years                                |       |                     | 62.4       |   |   |
| More than 10 years                        |       |                     | 90.1       |   |   |
| Total maturities of debt securities       |       |                     | $          | 235.0 |   |   |

 

**Investments in VariableInterest Entities**

We have a significant interest in the following variable interestentities (VIE) for which we are not the primary beneficiary:
| **VIE**                                 | ** ** | **Nature of  Involvement**                    | ** ** | **Date of  Involvement** |
|-----------------------------------------|------------|-----------------------------------------------|------------|--------------------------|
| Power projects and fuel supply entities |       | Equity investment and  guarantees             |       | Prior to 2003            |
| Power contract monetization entities    |       | Power sale agreements,  loans, and guarantees |       | March 2005          |
| Oil & gas fields               |       | Equity investment                             |       | May 2006            |
| Retail power supply                     |       | Power sale agreement                          |       | September 2006      |

 

We discuss thenature of our involvement with the power contract monetization VIEs in the *Customer Contract Restructuring* section below.

The following is summary information available as of December 31,2006 about the VIEs in which we have a significant interest, but are not theprimary beneficiary:
| ** **                   | ** ** | **Power  Contract  Monetization  VIEs** | ** ** | **All  Other  VIEs** | ** ** | **Total** | ** ** |
|------------------------------|------------|-----------------------------------------|------------|----------------------|------------|-----------|------------|
| ** **                   | ** ** | ***(In millions)***                | ** ** |
| Total assets                 |       |                                    | $          | 746.1                |       |      | $          | 355.5 |   | $ | 1,101.6 |   |
| Total liabilities            |       |                                    | 592.6      |                 |       | 162.0     |       | 754.6 |   |
| Our ownership interest       |       |                                    | —     |                 |       | 51.5      |       | 51.5 |   |
| Other ownership interests    |       |                                    | 153.5      |                 |       | 142.0     |       | 295.5 |   |
| Our maximum exposure to loss |       |                                    | 65.8       |                 |       | 92.3      |       | 158.1 |   |
|                              |            |                                         |            |                      |            |           |            |  |  |  |  |  |

 

The maximumexposure to loss represents the loss that we would incur in the unlikely eventthat our interests in all of these entities were to become worthless and wewere required to fund the full amount of all guarantees associated with theseentities. Our maximum exposure to loss as of December 31, 2006 consists ofthe following:

 ̈  outstandingreceivables, loans, and letters of credit totaling $94.0 million,

 ̈  thecarrying amount of our investment totaling $51.4 million, and

 ̈  debtand performance guarantees totaling $12.7 million.

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

*Customer Contract Restructuring*

In March 2005,our merchant energy business closed a transaction in which we assumed from acounterparty two power sales contracts with existing VIEs. Under the contracts,we sell power to the VIEs which, in turn, sell that power to an electricdistribution utility through 2013.

The VIEspreviously were created by the counterparty to issue debt in order to monetizethe value of the original contracts to purchase and sell power. The differencebetween the contract prices at which the VIEs purchase and sell power is usedto service the debt of the VIEs, which totaled $568 million at December 31,2006.

The marketprice for power at the closing of our transaction was higher than the contractprice under the existing power sales contracts we assumed. Therefore, we receivedcompensation totaling $308.5 million, equal to the net present value ofthe difference between the contract price under the power sales contracts andthe market price of power at closing. We used a portion of this amount tosettle $68.5 million of existing derivative liabilities with the samecounterparty, and we also loaned $82.8 million to the holder of the equityin the VIEs. As a result, we received net cash at closing of$157.2 million. We also guaranteed our subsidiaries’ performance under thepower sales contracts.

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The table below summarizes the transactionand the net cash received at closing:
| ** **                                                                                                                   | ** ** | ***(In millions)*** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------|------------|
| Gross compensation from original power sales contracts counterparty  equal to fair value of power sales contracts at closing |       |                     | $          | 308.5 |   |   |
| Settlement of existing derivative liabilities                                                                                |       |                     | (68.5      | ) |   |
| Third-party loan secured by equity in VIE                                                                                    |       |                     | (82.8      | ) |   |
| Net cash received at closing                                                                                                 |       |                     | $          | 157.2 |   |   |

 

We recorded the closing of this transaction in our financial statementsas follows:
| ** **                                                                   | ** ** | **Balance  Sheet**                             | ** ** | **Cash  Flows**        |
|------------------------------------------------------------------------------|------------|------------------------------------------------|------------|------------------------|
| Fair value of power sales  contracts assumed (designated as cash-flow hedge) |       | Risk management liabilities                    |       | Financing cash inflow  |
| Settlement of existing  derivative liabilities                               |       | Mark-to-market and risk management liabilities |       | Operating cash outflow |
| Third-party loan                                                             |       | Other assets                                   |       | Investing cash outflow |

 

We recorded thegross compensation we received to assume the power sales contracts as afinancing cash inflow because it constitutes a prepayment for a portion of themarket price of power, which we will sell to the VIEs over the term of thecontracts and does not represent a cash inflow from current period operatingactivities. We record the ongoing cash flows related to the sale of power tothe VIEs as a financing cash inflow in accordance with SFAS No. 149, *Amendment of FASB Statement No. 133 onDerivative and Hedging Activities*.

If the electricdistribution utility were to default under its obligation to buy power from theVIEs, the equity holder could transfer its equity interests to us in lieu ofrepaying the loan. In this event, we would have the right to seek recovery ofour losses from the electric distribution utility.

 

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**5**Intangible Assets

**Goodwill**

Goodwill is the excess of the cost of anacquisition over the fair value of the net assets acquired. Our goodwillbalance is primarily related to our merchant energy business acquisitions thatoccurred in 2002 and 2003. The changes in the carrying amount of goodwill forthe years ended December 31, 2006 and 2005 are as follows:
| ***2006***   | ** **   | **Balance at  January 1,** | ** ** | **Goodwill  Acquired** | ** ** | **Other(a)** | ** ** | **Balance at  December 31,** | ** ** |
|--------------|--------------|--------------------------------------|------------|------------------------|------------|--------------|------------|----------------------------------------|------------|
| ** **   | *** *** | ***(In millions)***             | ** ** |
| **Goodwill** | ** **   |                                 | **$**      | **147.1**              | ** ** |         |       | **$**                                  | **11.1**   | ** ** |   |   | **$** | **(0.6** | **)** |   |   | **$** | **157.6** | ** ** |   |
|              |              |                                      |            |                        |            |              |            |                                        |            |  |  |  |  |  |  |  |  |  |  |  |  |

 
| ***2005*** | ** ** | **Balance at  January 1,** | ** ** | **Goodwill  Acquired** | ** ** | **Other** | ** ** | **Balance at  December 31,** | ** ** |
|------------|------------|--------------------------------------|------------|------------------------|------------|-----------|------------|----------------------------------------|------------|
| ** ** | ** ** | ***(In millions)***             | ** ** |
| Goodwill   |       |                                 | $          | 144.8                  |       |      |       | $                                      | 2.3        |   |   |   | $ | — |   |   |   | $ | 147.1 |   |   |
|            |            |                                      |            |                        |            |           |            |                                        |            |  |  |  |  |  |  |  |  |  |  |  |  |

(a)             Otherrepresents purchase price adjustments.

Goodwill is not amortized; rather, it is evaluated for impairment atleast annually. We evaluated our goodwill in 2006 and 2005 and determined thatit was not impaired. For tax purposes, $128.5 million of our goodwillbalance is deductible.

**Intangible Assets Subject to Amortization**

Intangible assets with finite lives aresubject to amortization over their estimated useful lives. The primary assetsincluded in this category are as follows:
| ***At December 31,***  | ** ** | **2006**                    | ** ** | **2005**                            | ** ** |
|----------------------------------|------------|-----------------------------|------------|-------------------------------------|------------|
| *** ***                     | ** ** | **Gross  Carrying  Amount** | ** ** | **Accumul-  ated  Amortiz-  ation** | ** ** | **Net  Asset** | ** ** | **Gross  Carrying  Amount** | ** ** | **Accumul-  ated  Amortiz-  ation** | ** ** | **Net  Asset** | ** ** |
| *** ***                     | ** ** | ***(In millions)***    | ** ** |
| Software                         | ** ** |                        | **$**      | **392.3**                           | ** ** |   |   | **$** | **(182.6** | **)** |   | **$** | **209.7** |   |   | $ | 364.7 |   |   |   | $ | (156.5 | ) |   | $ | 208.2 |   |
| Permits and licenses             | ** ** |                        | **60.4**   | ** **                          |       |   | **(5.9** | **)** |   | **54.5** |   |   | 49.4 |   |   |   | (12.6 | ) |   | 36.8 |   |
| Operating manuals and procedures | ** ** |                        | **38.5**   | ** **                          |       |   | **(7.1** | **)** |   | **31.4** |   |   | 38.6 |   |   |   | (6.0 | ) |   | 32.6 |   |
| Other                            | ** ** |                        | **26.3**   | ** **                          |       |   | **(17.2** | **)** |   | **9.1** |   |   | 29.7 |   |   |   | (14.3 | ) |   | 15.4 |   |
| Total                            | ** ** |                        | **$**      | **517.5**                           | ** ** |   |   | **$** | **(212.8** | **)** |   | **$** | **304.7** |   |   | $ | 482.4 |   |   |   | $ | (189.4 | ) |   | $ | 293.0 |   |

 

*BGE had intangible assets with a grosscarrying amount of $191.3 million and accumulated amortization of $109.2million at December 31, 2006 and $181.4 million and accumulatedamortization of $98.7 million at December 31, 2005 that are includedin the table above. Substantially all of BGE’s intangible assets relate tosoftware.*

We recognized amortization expense related toour intangible assets as follows:
| ***Year Ended December 31,*** | ** ** | **2006**                 | ** ** | **2005** | ** ** | **2004** | ** ** |
|----------------------------------------------|------------|--------------------------|------------|----------|------------|----------|------------|
| ** **                                   | ** ** | ***(In millions)*** | ** ** |
| Nonregulated businesses                      | ** ** | **$**                    | **37.2**   |     | $          | 30.6     |       | $ | 25.0 |   |
| BGE                                          | ** ** | **18.6**                 |       | 26.3     |       | 41.4     |       |
| Total Constellation Energy                   | ** ** | **$**                    | **55.8**   |     | $          | 56.9     |       | $ | 66.4 |   |

The following is our, and BGE’s, estimated amortization expense for2007 through 2011 for the intangible assets included in our, and BGE’s,Consolidated Balance Sheets at December 31, 2006:
| ***Year Ended December 31,***                    | ** ** | **2007**                 | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** |
|-----------------------------------------------------------------|------------|--------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
| ** **                                                      | ** ** | ***(In millions)*** | ** ** |
| Estimated amortization expense—Nonregulated  businesses    |       | $                        | 41.6       |     | $          | 36.3     |       | $        | 29.0       |     | $          | 20.8 |   | $ | 15.2 |   |
| Estimated amortization expense—BGE                         |       | 19.3                     |       | 16.7     |       | 13.4     |       | 12.0     |       | 9.9      |       |
| Total estimated amortization expense—Constellation  Energy |       | $                        | 60.9       |     | $          | 53.0     |       | $        | 42.4       |     | $          | 32.8 |   | $ | 25.1 |   |

 

**Unamortized Energy Contracts**

As discussed in*Note 1*, unamortized energycontract assets and liabilities represent the remaining unamortized balance ofnonderivative energy contracts acquired or derivatives designated as normalpurchases and normal sales, which we previously recorded as mark-to-marketenergy or risk management assets and liabilities.

During 2005, weacquired several pre-existing nonderivative contracts that had been originatedby other parties in prior periods when market prices were lower than currentlevels. We received approximately $530 million in cash and otherconsideration and recorded a liability in “Unamortized energy contracts.” Inaddition, during 2005, we designated as normal purchases and normal salescontracts that we had previously recorded as cash-flow hedges in “Riskmanagement liabilities.” This resulted in a reclassification of$888.5 million from “Risk management liabilities” to “Unamortized energycontract liabilities.”

We present separately in our ConsolidatedBalance Sheets the net unamortized energy contract assets and liabilities forthese contracts. The table below presents the gross and net carrying amount andaccumulated amortization of the net liability that we have recorded in ourConsolidated Balance Sheets:
| ***At December 31***     | ** ** | **2006**                 | ** **   | **2005**                            | ** ** |
|------------------------------------|------------|--------------------------|--------------|-------------------------------------|------------|
| ** **                         | ** ** | **Carrying  Amount**     | ** **   | **Accumul-  ated  Amortiz-  ation** | ** ** | **Net  Liability** | ** ** | **Carrying  Amount** | ** ** | **Accumul-  ated  Amortiz-  ation** | ** ** | **Net  Liability** | ** ** |
| ** **                         | ** ** | ***(In millions)*** | ** **   |
| Unamortized energy contracts,  net | ** ** | **$**                    | **(1,642.0** | **)**                               |       | **$** | **464.5** | ** ** |   | **$** | **(1,177.5** | **)** | $ | (1,449.2 | ) |   | $ | 37.8 |   |   | $ | (1,411.4 | ) |
|                                    |            |                          |              |                                     |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

The table below presents the estimated net favorableimpact on our operating results for the amortization for these assets andliabilities over the next five-years:
| ***Year Ended December 31,*** | ** ** | **2007**                 | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** |
|----------------------------------------------|------------|--------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
| ** **                                   | ** ** | ***(In millions)*** | ** ** |
| Estimated amortization                       |       | $                        | 342.8      |     | $          | 255.4    |       | $        | 178.0      |     | $          | 166.6 |   | $ | 41.8 |   |
|                                              |            |                          |            |          |            |          |            |          |            |          |            |  |  |  |  |  |

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**6**Regulatory Assets (net)

As discussed in *Note 1*, the Maryland PSC and the FERC provide the finaldetermination of the rates we charge our customers for our regulatedbusinesses. Generally, we use the same accounting policies and practices usedby nonregulated companies for financial reporting under accounting principlesgenerally accepted in the United States of America. However, sometimes theMaryland PSC or FERC orders an accounting treatment different from that used bynonregulated companies to determine the rates we charge our customers. Whenthis happens, we must defer certain regulated expenses and income in ourConsolidated Balance Sheets as regulatory assets and liabilities. We thenrecord them in our Consolidated Statements of Income (using amortization) whenwe include them in the rates we charge our customers.

We summarize regulatory assets and liabilities in the following table,and we discuss each of them separately below.
| ***At December 31,***                          | ** ** | **2006**                 | ** ** | **2005** | ** ** |
|----------------------------------------------------------|------------|--------------------------|------------|----------|------------|
| ** **                                               | ** ** | ***(In millions)*** | ** ** |
| Deferred fuel costs                                      | ** ** | ** **               |       |     |       |
| Rate stabilization deferral                              | ** ** | **$**                    | **326.9**  |     | $          | — |   |
| Other                                                    | ** ** | **37.8**                 |       | 16.2     |       |
| Electric generation-related regulatory asset             | ** ** | **154.8**                |       | 173.6    |       |
| Net cost of removal                                      | ** ** | **(161.3**               | **)**      | (148.7   | )          |
| Income taxes recoverable through future rates (net)      | ** ** | **67.1**                 |       | 70.9     |       |
| Deferred postretirement and postemployment benefit costs | ** ** | **19.3**                 |       | 22.6     |       |
| Deferred environmental costs                             | ** ** | **10.0**                 |       | 14.9     |       |
| Workforce reduction costs                                | ** ** | **4.9**                  |       | 7.3      |       |
| Other (net)                                              | ** ** | **(8.0**                 | **)**      | (2.5     | )          |
| Total regulatory assets (net)                            | ** ** | **451.5**                |       | 154.3    |       |
| Less: Current portion of regulatory assets (net)         | ** ** | **62.5**                 |       | —   |       |
| Long-term portion of regulatory assets (net)             | ** ** | **$**                    | **389.0**  |     | $          | 154.3 |   |

 

**Deferred Fuel Costs**

*Rate Stabilization Deferral*

In June 2006,Senate Bill 1 was enacted in Maryland, which imposes a rate stabilizationmeasure that caps rate increases by BGE for residential electric customers at15% from July 1, 2006 to May 31, 2007. As a result, BGE is recordinga regulatory asset on its Consolidated Balance Sheets equal to the differencebetween the costs to purchase power and the revenues collected from customers,as well as related carrying charges based on short-term interest rates from July 1,2006 to May 31, 2007. During 2006, BGE deferred $326.9 million ofelectricity purchased for resale expenses and carrying charges as a regulatoryasset related to the rate stabilization plan. BGE will amortize the regulatoryasset to earnings over a period not to exceed ten years once collection fromcustomers begins.

*Other*

As described in *Note 1*, deferred fuel costs are the difference betweenour actual costs of purchased energy and our fuel rate revenues collected fromcustomers. We reduce deferred fuel costs as we collect them from or refund themto our customers.

We excludedeferred fuel costs from rate base because their existence is relatively short-lived.These costs are recovered in the following year through our fuel rates.

**Electric Generation-Related Regulatory Asset**

As a result of the deregulation of electricgeneration, BGE ceased to meet the requirements for the application of SFAS No. 71for the previous electric generation portion of its business. In accordancewith SFAS No. 101, *RegulatedEnterprises—Accounting for the Discontinuation of Application of FASB StatementNo. 71*, and EITF 97-4, *Deregulationof the Pricing of Electricity—Issues Related to the Application of FASBStatements No. 71 and 101*. BGE wrote-off all of its individual,generation-related regulatory assets and liabilities. BGE established asingle, generation-related regulatory asset to be collected through itsregulated transmission and distribution business, which is being amortized on abasis that approximates the pre-existing individual regulatory assetamortization schedules.

A portion of this regulatory asset representsincome taxes recoverable through future rates that do not earn a regulated rateof return. These amounts were $89.4 million as of December 31, 2006 and$97.9 million as of December 31, 2005. We will continue to amortize thisamount through 2017.

Another portionof this regulatory asset represents the decommissioning and decontaminationfund payment for federal uranium enrichment facilities that do not earn aregulated rate of return on the rate base investment. These amounts were $5.5million at December 31, 2006 and $8.6 million at December 31, 2005.Prior to the deregulation of electric generation, these costs were recoveredthrough the electric fuel rate mechanism, and were excluded from rate base. Wewill continue to amortize this amount through 2008.

**Net Cost of Removal**

As discussed in *Note 1*, we use the group depreciation method for theregulated business. This method is currently an acceptable method of accountingunder accounting principles generally accepted in the United States of Americaand is widely used in the energy, transportation, and telecommunicationindustries.

Historically, under the group depreciationmethod, the anticipated costs of removing assets upon retirement were providedfor over the life of those assets as a component of depreciation expense.However, effective January 1, 2003, we adopted SFAS No. 143, *Accounting for Asset Retirement Obligations.*In addition to providing the accounting requirements for recognizing anestimated liability for legal obligations associated with the retirement oftangible long-lived assets, SFAS No. 143 precludes the recognition ofexpected net future costs of removal as a component of depreciation expense oraccumulated depreciation.

BGE is requiredby the Maryland PSC to use the group depreciation method, including cost ofremoval, under regulatory accounting. For ratemaking purposes, net cost ofremoval is a component of accumulated depreciation and is included as a netreduction to BGE’s rate base investment. In accordance with SFAS No. 71,BGE continues to accrue for the future cost of removal for its regulated gasand electric assets by increasing its regulatory liability. This liability isrelieved when actual removal costs are incurred.

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**Income Taxes Recoverable Through Future Rates (net)**

As described in*Note 1*, income taxesrecoverable through future rates are the portion of our net deferred income taxliability that is applicable to our regulated business, but has not beenreflected in the rates we charge our customers. These income taxes representthe tax effect of temporary differences in depreciation and the allowance forequity funds used during construction, offset by differences in deferred taxrates and deferred taxes on deferred investment tax credits. We amortize theseamounts as the temporary differences reverse.

**Deferred Postretirement and Postemployment Benefit Costs**

Deferredpostretirement and postemployment benefit costs are the costs we recorded underSFAS No. 106, *Employers’ Accounting forPostretirement Benefits Other Than Pensions,* and SFAS No. 112, *Employers’ Accounting for Postemployment Benefits,*in excess of the costs we included in the rates we charge our customers. Webegan amortizing these costs over a 15-year period in 1998.

**Deferred Environmental Costs**

Deferredenvironmental costs are the estimated costs of investigating and cleaning upcontaminated sites we own. We discuss this further in *Note 12*. We amortized$21.6 million of these costs (the amount we had incurred through October 1995)and are amortizing $6.4 million of these costs (the amount we incurredfrom November 1995 through June 2000) over 10-year periods inaccordance with the Maryland PSC’s orders. We applied for and received raterelief for an additional $5.4 million of clean-up costs incurred duringthe period from July 2000 through November 2005. These costs arebeing amortized over a 10-year period that began in January 2006.

**Workforce Reduction Costs**

The portions ofthe costs associated with our Voluntary Special Early Retirement Program andworkforce reduction programs that relate to BGE’s gas business are deferred asregulatory assets in accordance with the Maryland PSC’s orders in prior ratecases. As a result of a 2005 gas base rate case, the remaining regulatoryassets associated with workforce reductions totaling $7.3 million as of December 31,2005 are being amortized over a 3-year period that began in January 2006.These remaining regulatory assets were previously amortized over 5-yearperiods beginning in January and February 2002.

**Other (Net)**

Otherregulatory assets are comprised of a variety of current assets and liabilitiesthat do not earn a regulatory rate of return due to their short-term nature.

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**7**Pension, Postretirement, Other Postemployment, and Employee Savings PlanBenefits

We offer pension, postretirement, otherpostemployment, and employee savings plan benefits. BGE employees participatein the benefit plans that we offer. We describe each of our plans separatelybelow. Nine Mile Point offers its own pension, postretirement, otherpostemployment, and employee savings plan benefits to its employees. Thebenefits for Nine Mile Point are included in the tables beginning below.

We use a December 31 measurement date for our pension,postretirement, other postemployment, and employee savings plans. In 2006, theFASB issued SFAS No. 158, which was adopted on December 31, 2006. Wediscuss SFAS No. 158 in more detail in *Note 1*. Thefollowing table summarizes our defined benefit liabilities and their classificationin our Consolidated Balance Sheets: 
| ***At December 31,***                       | ** ** | **2006**                 | ** ** | **2005** | ** ** |
|-------------------------------------------------------|------------|--------------------------|------------|----------|------------|
| ** **                                            | ** ** | ***(In millions)*** | ** ** |
| Pension benefits                                      | ** ** | **$**                    | **468.6**  |     | $          | 401.4 |   |
| Postretirement benefits                               | ** ** | **441.5**                |       | 327.9    |       |
| Postemployment benefits                               | ** ** | **57.0**                 |       | 54.7     |       |
| Total defined benefit obligations                     | ** ** | **967.1**                |       | 784.0    |       |
| Less: Amount  recorded in accrued expenses and other* | ** ** | **38.8**                 |       | —   |       |
| Total noncurrent defined benefit obligations          | ** ** | **$**                    | **928.3**  |     | $          | 784.0 |   |

** Amountrecorded as current portion of defined benefit liability in 2006 is based onthe expected cash payments associated with unfunded plans during the next 12months. Constellation Energy did not record the current portion of its definedbenefit obligation prior to the December 2006 implementation of SFAS No. 158.*

**Pension Benefits**

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

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

We fund thequalified plans by contributing at least the minimum amount required under IRSregulations. We calculate the amount of funding using an actuarial methodcalled the projected unit credit cost method. The assets in all of the plans atDecember 31, 2006 and 2005 were mostly marketable equity and fixed incomesecurities.

**Postretirement Benefits**

We sponsordefined benefit postretirement health care and life insurance plans that coverthe majority of our employees. Generally, we calculate the benefits under theseplans based on age, years of service, and pension benefit levels or final basepay. We do not fund these plans. For nearly all of the health care plans,retirees make contributions to cover a portion of the plan 

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costs. For thelife insurance plan, retirees do not make contributions to cover a portion ofthe plan costs.

Effective in2002, we amended our postretirement medical plans for all subsidiaries otherthan Nine Mile Point. Our contributions for retiree medical coverage for futureretirees who were under the age of 55 on January 1, 2002 are capped at the2002 level. We also amended our plans to increase the Medicare eligibleretirees’ share of medical costs.

In 2003, the President signed into law the Medicare Prescription DrugImprovement and Modernization Act of 2003 (the Act). This legislation providesa prescription drug benefit for Medicare beneficiaries, a benefit that weprovide to our Medicare eligible retirees. Our actuaries concluded thatprescription drug benefits available under our postretirement medical plan are “actuariallyequivalent” to Medicare Part D and thus qualify for the subsidy under theAct. In 2005, the Center for Medicare and Medicaid Services accepted ourapplication to receive a tax reimbursement for eligible prescription drugcosts, and we began to receive the subsidy in 2006. The actual subsidy offsetsa portion of our share of the cost of the underlying postretirementprescription drug coverage. This legislation reduced our AccumulatedPostretirement Benefit Obligation by $42.6 million at January 1, 2005and our annual postretirement benefit expense in 2005 by $5.4 million.This subsidy reduced our 2006 cash medical costs by $1.8 million, or by 7%.

**Pension Liability Adjustments**

Our pension accumulated benefit obligationhas exceeded the fair value of our plan assets since 2001. At December 31,2006 and 2005, our pension obligations were greater than the fair value of ourplan assets for our qualified and our nonqualified pension plans as follows:
| ** **                                | ** ** | **Qualified Plans** | ** ** | **Non-Qualified** | ** ** | ** **  | ** ** |
|-------------------------------------------|------------|--------------------------|------------|-------------------|------------|-------------|------------|
| ***At December 31, 2006*** | ** ** | **Nine Mile**       | ** ** | **Other**         | ** ** | **Plans**   | ** ** | **Total** | ** ** |
| *** ***                              | ** ** | ***(In millions)*** | ** ** | ** **        | ** ** |
| Accumulated benefit  obligation           | ** ** |                     | **$**      | **107.5**         | ** ** |        | **$**      | **1,306.0** | ** ** |   | **$** | **63.8** | ** ** |   | **$** | **1,477.3** | ** ** |
| Fair value of assets                      | ** ** |                     | **54.6**   | ** **        |       | **1,106.6** | ** ** |   | **—** | ** ** |   | **1,161.2** | ** ** |
| Unfunded obligation                       | ** ** |                     | **$**      | **52.9**          | ** ** |        | **$**      | **199.4** | ** ** |   | **$** | **63.8** | ** ** |   | **$** | **316.1** | ** ** |

 
| ** **                              | ** ** | **Qualified Plans** | ** ** | **Non-Qualified** | ** ** | ** ** | ** ** |
|-----------------------------------------|------------|--------------------------|------------|-------------------|------------|------------|------------|
| **At December 31, 2005** | ** ** | **Nine Mile**       | ** ** | **Other**         | ** ** | **Plans**  | ** ** | **Total** | ** ** |
| ** **                              | ** ** | ***(In millions)*** | ** ** | ** **        | ** ** |
| Accumulated benefit  obligation         |       |                     | $          | 127.1             |       |       | $          | 1,325.1 |   |   | $ | 56.3 |   |   | $ | 1,508.5 |   |
| Fair value of assets                    |       |                     | 84.9       |              |       | 1,022.2    |       |   | — |   |   | 1,107.1 |   |
| Unfunded obligation                     |       |                     | $          | 42.2              |       |       | $          | 302.9 |   |   | $ | 56.3 |   |   | $ | 401.4 |   |

 

We were required to remeasure the additionalminimum pension liability prior to calculating the impact of adopting SFASNo. 158 on December 31, 2006. We recorded the additional minimumpension liability adjustments as follows:
| ** **              | ** ** | **Increase (Decrease)** | ** ** |
|-------------------------|------------|------------------------------|------------|
| ** **              | ** ** | **Pension  Liability**       | ** ** | **Intangible** | ** ** | **Accumulated Other  Comprehensive Loss** | ** ** |
| ** **              | ** ** | **Adjustment**               | ** ** | **Asset *** | ** ** | **Pre-tax** | ** ** | **After-tax** | ** ** |
| ** **              | ** ** | ***(In millions)***     | ** ** |
| Cumulative through 2004 |       |                         | $          | 359.6 |   |   |   | $ | 40.6 |   |   | $ | (319.0 | ) |   | $ | (192.8 | ) |   |
| 2005                    |       |                         | 121.4      |   |   |   | (6.1 | ) |   | (127.5 | ) |   | (77.1 | ) |   |
| 2006                    |       |                         | (131.1     | ) |   |   | (5.9 | ) |   | 125.2 |   |   | 75.6 |   |   |
| Total                   |       |                         | $          | 349.9 |   |   |   | $ | 28.6 |   |   | $ | (321.3 | ) |   | $ | (194.3 | ) |   |

 

** Included in “Other assets” in ourConsolidated Balance Sheets.*

Upon adoptionof SFAS No. 158, we reversed the intangible asset associated with theminimum pension liability adjustment, increased our pension and postretirementliabilities, and reduced equity. The following table summarizes the impact ofthe adoption of SFAS No. 158 at December 31, 2006:
| ** **             | ** ** | **Increase (Decrease)** | ** ** |
|------------------------|------------|------------------------------|------------|
| ** **             | ** ** | **Pension**                  | ** ** | **Postretirement  Benefit** | ** ** | **Intangible** | ** ** | **Accumulated Other  Comprehensive Loss** | ** ** |
| ** **             | ** ** | **Liability**                | ** ** | **Liability** | ** ** | **Asset** | ** ** | **Pre-tax** | ** ** | **After-tax** | ** ** |
| ** **             | ** ** | ***(In millions)***     | ** ** |
| December 31, 2006 |       |                         | $          | 152.5 |   |   |   | $ | 99.7 |   |   |   | $ | (28.6 | ) |   | $ | (280.8 | ) |   | $ | (169.5 | ) |   |
|                        |            |                              |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

*SFAS No. 158 reduced our deferredincome tax liability by $111.3 million.*

**Obligations and Assets**

As a result ofworkforce reduction initiatives in the generation business, pension andpostretirement special termination benefits were recorded in 2006 and 2005. Wediscuss the workforce reduction initiatives further in *Note 2.*

We show the change in the benefit obligationsand plan assets of the pension and postretirement benefit plans in thefollowing tables. Postretirement benefit plan amounts are presented net ofexpected reimbursements under Medicare Part D. 
| ** **                                | ** ** | **Pension  Benefits**    | ** **  | **Postretirement  Benefits** | ** ** |
|-------------------------------------------|------------|--------------------------|-------------|------------------------------|------------|
| ** **                                | ** ** | **2006**                 | ** **  | **2005**                     | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                | ** ** | ***(In millions)*** | ** **  |
| **Change in benefit obligation (1)** | ** ** | ** **               | ** **  | ** **                   |       |   |   |   |   |
| Benefit obligation at  January 1     | ** ** | **$**                    | **1,678.6** |                         | $          | 1,513.2 | ** ** | **$** | **460.4** |   | $ | 423.2 |   |
| Service cost                              | ** ** | **49.0**                 |        | 44.8                         | ** ** | **7.7** |   | 7.6 |   |
| Interest cost                             | ** ** | **89.3**                 |        | 83.9                         | ** ** | **23.7** |   | 23.8 |   |
| Plan participants’ contributions     |       | —                   |        | —                       | ** ** | **8.3** |   | 7.4 |   |
| Actuarial (gain) loss                     | ** ** | **(49.1**                | **)**       | 143.6                        | ** ** | **(27.1** | **)** | 35.6 |   |
| Special termination benefits              | ** ** | **4.2**                  |        | (0.4                         | )          | **3.5** |   | — |   |
| Benefits paid (2)                         | ** ** | **(142.2**               | **)**       | (106.5                       | )          | **(35.0** | **)** | (37.2 | ) |
| Benefit obligation at December 31    | ** ** | **$**                    | **1,629.8** |                         | $          | 1,678.6 | ** ** | **$** | **441.5** |   | $ | 460.4 |   |

 

*(1)    Amounts reflect projected benefit obligationfor pension benefits and accumulated postretirement benefit obligation forpostretirement benefits.*

*(2)    Benefitspaid include annuity payments, lump-sum distributions, and transfers tononqualified deferred compensation plans.*

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| ** **                                    | ** ** | **Pension  Benefits**    | ** **  | **Postretirement  Benefits** | ** ** |
|-----------------------------------------------|------------|--------------------------|-------------|------------------------------|------------|
| ** **                                    | ** ** | **2006**                 | ** **  | **2005**                     | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                    | ** ** | ***(In millions)*** | ** **  |
| **Change in plan assets**                     | ** ** | ** **               | ** **  | ** **                   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Fair value of plan assets at  January 1  | ** ** | **$**                    | **1,107.1** |                         | $          | 1,084.4 | ** ** | **$** | **—** |   | $ | — |   |
| Actual return on plan assets                  | ** ** | **141.1**                |        | 76.2                         |       | **—** |   | — |   |
| Employer contribution(1)                      | ** ** | **55.2**                 |        | 53.0                         | ** ** | **26.7** |   | 29.8 |   |
| Plan participants’ contributions         |       | **—**               |        | —                       | ** ** | **8.3** |   | 7.4 |   |
| Benefits paid(2)                              | ** ** | **(142.2**               | **)**       | (106.5                       | )          | **(35.0** | **)** | (37.2 | ) |
| Fair value of plan assets at December 31 | ** ** | **$**                    | **1,161.2** |                         | $          | 1,107.1 | ** ** | **$** | **—** |   | $ | — |   |

 

*(1)**            **Includes benefit payments for unfundedplans.*

*(2)**  **Benefits paid include annuitypayments, lump-sum distributions, and transfers to nonqualified deferredcompensation plans.*

**Net Periodic Benefit Cost and AmountsRecognized in Other Comprehensive Income**

We show the components of net periodicpension benefit cost in the following table:
| ***Year Ended December 31,***         | ** ** | **2006**                 | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|------------------------------------------------------|------------|--------------------------|------------|------------|------------|------------|------------|
| ** **                                           | ** ** | ***(In millions)*** | ** ** |
| **Components of net periodic pension benefit  cost** |       |                     | ** ** | ** ** | ** ** | ** ** | ** ** |
| Service cost                                         | ** ** | **$**                    | **49.0**   |       | $          | 44.8       |       | $ | 40.1 |   |
| Interest cost                                        | ** ** | **89.3**                 |       | 83.9       |       | 82.3       |       |
| Expected return on plan assets                       | ** ** | **(96.6**                | **)**      | (100.2     | )          | (97.9      | )          |
| Amortization of unrecognized  prior service cost     | ** ** | **5.7**                  |       | 5.7        |       | 5.8        |       |
| Recognized net actuarial loss                        | ** ** | **37.3**                 |       | 25.1       |       | 14.3       |       |
| Amount capitalized as  construction cost             | ** ** | **(13.4**                | **)**      | (7.4       | )          | (4.5       | )          |
| Net periodic pension benefit cost (1)                | ** ** | **$**                    | **71.3**   |       | $          | 51.9       |       | $ | 40.1 |   |

 

*(1)**            **Net periodic pension benefit costexcludes SFAS No. 88 settlement charge of $12.7 million, and terminationbenefits of $4.2 million in 2006, SFAS No. 88 settlement charge of$4.4 million in 2005, and  SFAS No. 88settlement charge of $2.8 million and termination benefits of$2.4 million in 2004. BGE’s portion of our net periodic pension benefitcosts, excluding amount capitalized, was $25.0 million in 2006,$15.0 million in 2005,and $8.6 million in 2004. The vast majority of our retirees are BGEemployees.*

We show the components of net periodicpostretirement benefit cost in the following table:
| ***Year Ended December 31,***                | ** **   | **2006**                 | ** **   | **2005**   | ** ** | **2004**   | ** ** |
|-------------------------------------------------------------|--------------|--------------------------|--------------|------------|------------|------------|------------|
| *** ***                                                | *** *** | ***(In millions)*** | *** *** |
| **Components of net periodic postretirement  benefit cost** | ** **   | ** **               | ** **   | ** ** | ** ** | ** ** | ** ** |
| Service cost                                                | ** **   | **$**                    | **7.7**      |       | $          | 7.6        |       | $ | 6.5 |   |
| Interest cost                                               | ** **   | **23.7**                 |         | 23.8       |       | 22.6       |       |
| Amortization of transition  obligation                      | ** **   | **2.1**                  |         | 2.1        |       | 2.1        |       |
| Recognized net actuarial loss                               | ** **   | **6.6**                  |         | 6.4        |       | 3.1        |       |
| Amortization of unrecognized  prior service cost       | ** **   | **(3.5**                 | **)**        | (3.5       | )          | (3.5       | )          |
| Amount capitalized as  construction cost                    | ** **   | **(8.2**                 | **)**        | (7.7       | )          | (7.0       | )          |
| Net periodic postretirement benefit cost (1)                | ** **   | **$**                    | **28.4**     |       | $          | 28.7       |       | $ | 23.8 |   |

 

*(1)**            **Net periodic postretirementbenefit cost excludes SFAS No. 106 termination benefits of $3.5 million in2006 and $1.2 million in 2004. BGE’s portion of our net periodicpostretirement benefit cost, excluding amounts capitalized, was $16.6 millionin 2006, $17.4 million in 2005, and $15.1 million in 2004.*

As a result of adopting SFAS No. 158, at December 31, 2006the following is a summary of amounts we have recorded in “Accumulated othercomprehensive income” and of expected amortization of those amounts over thenext twelve months:
| ***At December 31, 2006*** | ** ** | **Pension  Benefits**    | ** ** | **Postretirement  Benefits** | ** ** | **Estimated  Amortization  Next 12  Months** | ** ** |
|-------------------------------------------|------------|--------------------------|------------|------------------------------|------------|---------------------------------------------------|------------|
| ** **                                | ** ** | ***(In millions)*** | ** ** |
| Unrecognized net actuarial loss           |       |                     | $          | 475.7                        |       |                                              |       | $ | 116.6 |   |   |   | $ | 37.1 |   |   |
| Unrecognized prior service cost           |       |                     | 26.7       |                         |       |                                              | (29.7      | ) |   |   | 1.7 |   |   |
| Unrecognized transition  obligation       |       |                     | —     |                         |       |                                              | 12.8       |   |   |   | 2.1 |   |   |
| Total                                     |       |                     | $          | 502.4                        |       |                                              |       | $ | 99.7 |   |   |   | $ | 40.9 |   |   |

 

**Expected Cash Benefit Payments**

The pension and postretirement benefits weexpect to pay in each of the next five calendar years and in the aggregate forthe subsequent five years are shown below. These estimated benefits are basedon the same assumptions used to measure the benefit obligation at December 31,2006, but include benefits attributable to estimated future employee service.
| ** ** | ** ** | ** **               | ** ** | **Postretirement Benefits**  | ** ** |
|------------|------------|--------------------------|------------|-----------------------------------|------------|
| ** ** | ** ** | **Pension  Benefits***   | ** ** | **Before  Medicare  Part D** | ** ** | **Subsidy** | ** ** | **After  Medicare  Part D** | ** ** |
| ** ** | ** ** | ***(In millions)*** | ** ** |
| 2007       |       |                     | $          | 105.5                             |       |   |   | $ | 30.8 |   |   |   | $ | 2.7 |   |   |   | $ | 28.1 |   |   |
| 2008       |       |                     | 97.7       |                              |       |   | 31.9 |   |   |   | 2.9 |   |   |   | 29.0 |   |   |
| 2009       |       |                     | 100.3      |                              |       |   | 33.0 |   |   |   | 3.1 |   |   |   | 29.9 |   |   |
| 2010       |       |                     | 111.5      |                              |       |   | 33.8 |   |   |   | 3.2 |   |   |   | 30.6 |   |   |
| 2011       |       |                     | 108.4      |                              |       |   | 34.6 |   |   |   | 3.4 |   |   |   | 31.2 |   |   |
| 2012-2016  |       |                     | 688.5      |                              |       |   | 182.7 |   |   |   | 18.9 |   |   |   | 163.8 |   |   |

 

** Excludes transfers to nonqualifieddeferred compensation plans*

**Assumptions**

We made the assumptions below to calculateour pension and postretirement benefit obligations and periodic cost.
| ** **                     | ** ** | **Pension  Benefits** | ** ** | **Postretirement  Benefits** | ** ** | **Assumption  Impacts** | ** ** |
|--------------------------------|------------|-----------------------|------------|------------------------------|------------|-------------------------|------------|
| ** **                     | ** ** | **2006**              | ** ** | **2005**                     | ** ** | **2006**                | ** ** | **2005** | ** ** | **Calculation of** | ** ** |
| Discount rate                  | ** ** |                  | **6.00**   | **%**                        |       |                    | 5.50       | % |   |   | **6.00** | **%** |   |   | 5.50 | % |   | Benefit  Obligation and  Periodic Cost |   |
| Expected return on plan assets | ** ** |                  | **8.75**   | ** **                   |       |                    | 9.0        |   |   |   | **N/A** | ** ** |   |   | N/A |   |   | Periodic Cost |   |
| Rate of compensation increase  | ** ** |                  | **4.0**    | ** **                   |       |                    | 4.0        |   |   |   | **4.0** | ** ** |   |   | 4.0 |   |   | Benefit  Obligation and  Periodic Cost |   |

 

Our discountrate is based on a bond portfolio analysis of high quality corporate bondswhose maturities match our expected benefit payments. Our 8.75% overallexpected long-term rate of return on plan assets reflects our long-terminvestment strategy in terms of asset mix targets and expected returns for eachasset class. Effective in 2006, we reduced our assumed expected return onpension plan assets from 9.0% to 

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8.75% based on a fundamental analysis utilizing expected long-termreturns applied to our targeted asset allocation.

Annual health care inflation rate assumptionsalso impact the calculation of our postretirement benefit obligation andperiodic cost. We assumed the following health care inflation rates to produceaverage claims by year as shown below:
| ***At December 31,***  | ** ** | **2006** | ** ** | **2005** | ** ** |
|----------------------------------|------------|----------|------------|----------|------------|
| Next year                        | ** ** | **8.5%** |       | 9.0%     |       |
| Following year                   | ** ** | **8.0%** |       | 8.0%     |       |
| Ultimate trend rate              | ** ** | **5.0%** |       | 5.0%     |       |
| Year ultimate trend rate reached | ** ** | **2014** |       | 2010     |       |

 

A one-percentincrease in the health care inflation rate from the assumed rates wouldincrease the accumulated postretirement benefit obligation by approximately$32.1 million as of December 31, 2006 and would increase the combinedservice and interest costs of the postretirement benefit cost by approximately$2.2 million annually.

A one-percent decrease in the health care inflation rate from theassumed rates would decrease the accumulated postretirement benefit obligationby approximately $26.8 million as of December 31, 2006 and woulddecrease the combined service and interest costs of the postretirement benefitcost by approximately $1.8 million annually.

**Qualified Pension Plan Assets**

The asset allocations for our qualifiedpension plans were as follows:
| ***At December 31,*** | ** ** | **2006** | ** ** | **2005**   | ** ** |
|---------------------------------|------------|----------|------------|------------|------------|
| Equity securities               | ** ** |     | **64**     | **%**      |       |   | 59 | % |   |
| Debt securities                 | ** ** |     | **28**     | ** ** |       |   | 32 |   |   |
| Other                           | ** ** |     | **8**      | ** ** |       |   | 9 |   |   |
| Total                           | ** ** |     | **100**    | **%**      |       |   | 100 | % |   |

 

The category “Other”primarily represents investments in financial limited partnerships. Ourlong-term pension plan investment strategy is to seek an asset mix of 58%equity, 30% fixed income, and 12% other investments. We rebalance our portfolioperiodically when the sum of equity and other investments differs from 70% bythree percentage points or more, we change an outside investment advisor, or wemake contributions to the trust.

We determine expected return on plan assets using a market-relatedvalue of plan assets that recognizes asset gains and losses ratably over afive-year period.

**Contributions and Benefit Payments**

We contributed an additional $52 million to our qualified pensionplans in March 2006, even though there was no IRS required minimumcontribution in 2006. We expect to contribute $125 million to our pensionplans in 2007. Our non-qualified pension plans and our postretirement benefitprograms are not funded. We estimate that we will incur approximately$3.8 million in pension benefits for our non-qualified pension plans andapproximately $28 million for retiree health and life insurance costs netof Medicare Part D during 2007.

**Other Postemployment Benefits**

We provide the following postemployment benefits:

 ̈  healthand life insurance benefits to eligible employees determined to be disabledunder our Disability Insurance Plan,

 ̈  incomereplacement payments for Nine Mile Point union-represented employeesdetermined to be disabled, and

 ̈  incomereplacement payments for other employees determined to be disabled before November 1995(payments for employees determined to be disabled after that date are paid byan insurance company, and the cost is paid by employees).

We recognizedexpense associated with our other postemployment benefits of $9.6 million in2006, $9.2 million in 2005, and $10.8 million in 2004. BGE’s portionof expense associated with other postemployment benefits was $5.6 millionin 2006, $5.4 million in 2005, and $8.2 million in 2004. 

We assumed the discount rate for other postemployment benefits to be5.50% in 2006 and 5.25% in 2005. This assumption impacts the calculation of ourother postemployment benefit obligation and periodic cost.

**Employee Savings Plan Benefits**

We sponsor defined contribution savings plans that are offered to alleligible employees. The savings plans are qualified 401(k) plans under theInternal Revenue Code. In a defined contribution plan, the benefits aparticipant is to receive result from regular contributions to a participantaccount. Matching contributions to participant accounts are made under these plans.Matching contributions to these plans were:

 ̈  $20.0million, of which BGE contributed $5.4 million, in 2006,

 ̈  $18.6 million,of which BGE contributed $5.1 million, in 2005, and

 ̈  $16.7 million,of which BGE contributed $4.7 million, in 2004.

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**8** Credit Facilities and Short-Term Borrowings

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

**Constellation Energy**

Constellation Energy had committed bank lines of credit under creditfacilities of $4,550 million at December 31, 2006 for short-term financialneeds as follows:

 ̈  $1.0billion 364-day credit facility expiring in October 2007,

 ̈  $200million 364-day credit facility expiring in December 2007,

 ̈  $1.5 billionfive-year revolving credit facility expiring in March 2010,

 ̈  $1.1 billionfive-year revolving credit facility expiring in November 2010, and

 ̈  $750.0 millionfive-year revolving credit facility expiring in November 2010.

We enter intothese facilities to ensure adequate liquidity to support our operations.Currently, we use the facilities to issue letters of credit primarily for ourmerchant energy business. Additionally, we can borrow directly from the banksor use the facilities to allow the issuance of commercial paper with theexception of the $1.0 billion 364-day facility, which only supports $500.0million of letters of credit and the $200 million 364-day facility, whichonly supports letters of credit.

Thesefacilities can issue letters of credit up to approximately $4,050 million.Letters of credit issued under all of our facilities totaled $1,648 million at December 31,2006 and $2,486 million at December 31, 2005. The decrease in lettersof credit issued is primarily due to changes in collateral requirements withcounterparties as a result of commodity price changes.

In 2005, our merchant energy business executed several short-termrepurchase agreements that resulted in $0.7 million of net short-termborrowings which matured in January 2006.

**BGE**

BGE had nocommercial paper outstanding at December 31, 2006 or 2005.

BGE has a$400.0 million five-year revolving credit facility expiring in 2011. BGE canborrow directly from the banks or use the agreements to allow the issuance ofcommercial paper.

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**9**Long-Term Debt and Preference Stock

**Long-term Debt**

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

***ConstellationEnergy***

OnOctober 31, 2006, CEP entered into a $200.0 million secured revolvingcredit facility. The credit facility will mature on October 31, 2010. Theamount available for borrowing at any one time is limited to the borrowingbase, which is initially set at $75.0 million. At December 31, 2006, CEPhad $22.0 million of borrowings outstanding under this facility. As discussedin *Note 13,* in 2006, CEP executedfloating-to-fixed interest rate swaps related to $16.5 million of itsoutstanding debt.

In May 2006, we issued $122.0 million of tax-exempt variablerate notes to refinance tax-exempt pollution control loans. We used$75.0 million of the net proceeds to refinance a 6.00% pollution controlrevenue refunding loan in June 2006 and in July 2006 we used theremaining $47.0 million of proceeds to refinance a 5.55% pollution controlrevenue refunding loan.

***BGE***

*BGE’s FirstRefunding Mortgage Bonds*

BGE’s firstrefunding mortgage bonds are secured by a mortgage lien on all of its assets.The generating assets BGE transferred to subsidiaries of Constellation Energyalso remain subject to the lien of BGE’s mortgage, along with the stock of SafeHarbor Water Power Corporation and Constellation Enterprises, Inc.

BGE is required to make an annual sinking fund payment eachAugust 1 to the mortgage trustee. The amount of the payment is equal to 1%of the highest principal amount of bonds outstanding during the preceding12 months. The trustee uses these funds to retire bonds from any seriesthrough repurchases or calls for early redemption. However, the trustee cannotcall the two remaining outstanding bonds for early redemption:

 ̈  71¤2%Series, due 2007

 ̈  65¤8%Series, due 2008

*BGE’s Other Long-Term Debt*

In October 2006, BGE issued $300.0 million of 5.90% Notes, dueOctober 1, 2016 and $400.0 million of 6.35% Notes, due October 1,2036. We used the proceeds from these issuances for general corporate purposes,including refinancing the following long-term debt of BGE:

 ̈  $300.0million of 5.25% Notes, due December 15, 2006,

 ̈  $121.4million of 7.5% First Refunding Mortgage Bonds, due January 15, 2007, and

 ̈  $10.0million of 6.70% Medium-term Notes, Series D, due December 1, 2006.

On July 1,2000, BGE transferred $278.0 million of tax-exempt debt to our merchantenergy business related to the transferred generating assets. AtDecember 31, 2006, BGE remains contingently liable for the$147.8 million outstanding balance of this debt.

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We show the weighted-average interestrates and maturity dates for BGE’s fixed-rate medium-term notes outstanding at December 31,2006 in the following table.
| **Series** | ** ** | **Weighted-Average  Interest Rate** | ** ** | **Maturity  Dates** | ** ** |
|------------|------------|------------------------------------------|------------|---------------------|------------|
| E          |       |                                     | 6.66       | %                   |       | 2007-2012 |   |
| G          |       |                                     | 6.08       | %                   |       | 2008 |   |

 

Some of the medium-term notes include a “putoption.” These put options allow the holders to sell their notes back to BGE onthe put option dates at a price equal to 100% of the principal amount. Thefollowing is a summary of medium-term notes with put options.
| **Series E  Notes** | ** **   | **Principal**            | ** **   | **Put  Option Dates** | ** **   |
|---------------------|--------------|--------------------------|--------------|-----------------------|--------------|
| *** ***        | *** *** | ***(In millions)*** | *** *** | *** ***          | *** *** |
| 6.75%, due 2012     |         |                     | $            | 59.5                  |         |   |   | June 2007 |   |   |
| 6.75%, due 2012     |         |                     | 25.0         |                  |         |   | June 2007 |   |   |
| 6.73%, due 2012     |         |                     | 25.0         |                  |         |   | June 2007 |   |   |

 

*BGE DeferrableInterest Subordinated Debentures*

On November 21,2003, BGE Capital Trust II (BGE Trust II), a Delaware statutory trustestablished by BGE, issued 10,000,000 Trust Preferred Securities for$250 million ($25 liquidation amount per preferred security) with adistribution rate of 6.20%.

BGE Trust IIused the net proceeds from the issuance of common securities to BGE and theTrust Preferred Securities to purchase a series of 6.20% Deferrable InterestSubordinated Debentures due October 15, 2043 (6.20% debentures) from BGEin the aggregate principal amount of $257.7 million with the same terms asthe Trust Preferred Securities. BGE Trust II must redeem the Trust PreferredSecurities at $25 per preferred security plus accrued but unpaid distributionswhen the 6.20% debentures are paid at maturity or upon any earlier redemption.BGE has the option to redeem the 6.20% debentures at any time on or after November 21,2008 or at any time when certain tax or other events occur.

BGE Trust IIwill use the interest paid on the 6.20% debentures to make distributions on theTrust Preferred Securities. The 6.20% debentures are the only assets of BGETrust II.

BGE fully andunconditionally guarantees the Trust Preferred Securities based on its variousobligations relating to the trust agreement, indentures, 6.20% debentures, andthe preferred security guarantee agreement.

For the payment of dividends and in the event of liquidation of BGE,the 6.20% debentures are ranked prior to preference stock and common stock.

*RevolvingCredit Agreement*

On December 18, 2001, BGE’s subsidiary, District Chilled WaterPartnership (ComfortLink) entered into a $25.0 million loan agreement withthe Maryland Energy Financing Administration (MEFA). The terms of the loanexactly match the terms of variable rate, tax exempt bonds due December 1,2031 issued by MEFA for ComfortLink to finance the cost of building a chilledwater distribution system. The interest rate on this debt resets weekly. Thesebonds, and the corresponding loan, can be redeemed at any time at par plusaccrued interest while under variable rates. The bonds can also be converted toa fixed rate at ComfortLink’s option.

**Debt Compliance andCovenants**

The creditfacilities of Constellation Energy and BGE discussed in *Note 8* have limited material adversechange clauses that only consider a material change in financial condition andare not directly affected by decreases in credit ratings. If these clauses areinvoked, the lending institutions can decline to make new advances or issue newletters of credit, but cannot accelerate existing amounts outstanding. Thelong-term debt indentures of Constellation Energy and BGE do not containmaterial adverse change clauses or financial covenants.

Certain creditfacilities of Constellation Energy contain a provision requiring ConstellationEnergy to maintain a ratio of debt to capitalization equal to or less than 65%.At December 31, 2006, the debt to capitalization ratio as defined in thecredit agreements was 48%.

The creditagreement of BGE contains a provision requiring BGE to maintain a ratio of debtto capitalization equal to or less than 65%. At December 31, 2006, thedebt to capitalization ratio for BGE as defined in this credit agreement was49%. At December 31, 2006, no amounts were outstanding under theseagreements.

Failure byConstellation Energy, or BGE, to comply with these covenants could result inthe acceleration of the maturity of the debt outstanding under thesefacilities. The credit facilities of Constellation Energy contain usual andcustomary cross-default provisions that apply to defaults on debt byConstellation Energy and certain subsidiaries over a specified threshold. TheBGE credit facility also contains usual and customary cross-defaultprovisions that apply to defaults on debt by BGE over a specified threshold.The indenture pursuant to which BGE has issued and outstanding mortgage bondsprovides that a default under any debt instrument issued under the indenturemay cause a default of all debt outstanding under such indenture.

Constellation Energy also provides credit support to Calvert Cliffs,Ginna, and Nine Mile Point to ensure these plants have funds to meet expensesand obligations to safely operate and maintain the plants.

**Maturities ofLong-Term Debt**

Our long-term borrowings mature on thefollowing schedule:
| ***Year***                                     | ** ** | **Constellation  Energy** | ** ** | **Nonregulated  Businesses** | ** ** | **BGE** | ** ** |
|------------------------------------------------|------------|---------------------------|------------|------------------------------|------------|---------|------------|
| ** **                                     | ** ** | ***(In millions)***  | ** ** |
| 2007                                           |       |                      | $          | 600.0                        |       |    |       | $ | 20.5 |   |   | $ | 121.4 |   |
| 2008                                           |       |                      | —     |                         |       |    | 6.5        |   |   | 294.6 |   |
| 2009                                           |       |                      | 500.0      |                         |       |    | 1.2        |   |   | 11.5 |   |
| 2010                                           |       |                      | —     |                         |       |    | 22.3       |   |   | — |   |
| 2011                                           |       |                      | —     |                         |       |    | 36.5       |   |   | 22.0 |   |
| Thereafter                                     |       |                      | 1,942.9    |                         |       |    | 260.4      |   |   | 1,267.2 |   |
| Total long-term debt at December 31, 2006 |       |                      | $          | 3,042.9                      |       |    |       | $ | 347.4 |   |   | $ | 1,716.7 |   |

 

At December 31, 2006, we had long-term loans totaling $384.3 millionthat mature after 2006, which contain certain put options under which lenderscould potentially require us to repay the debt prior to maturity, or which areperiodically remarketed 

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and could require repayment following anyunsuccessful remarketing. As a result of these provisions, at December 31,2006, $136.9 million is classified as current portion of long-term debt atBGE.

**Weighted-AverageInterest Rates for Variable Rate Debt**

Our weighted-average interest rates forvariable rate debt were:
| ***At December 31,***                                 | ** ** | **2006**   | ** ** | **2005** | ** ** |
|-----------------------------------------------------------------|------------|------------|------------|----------|------------|
| ***Nonregulated Businesses (including  Constellation Energy)*** |       |       |       |     |       |
| Loans under  credit agreements                                  | ** ** | **3.69**   | **%**      | 4.71     | %          |
| Tax-exempt  debt                                                | ** ** | **3.63**   | **%**      | 2.77     | %          |
| Fixed-rate  debt converted to floating*                         | ** ** | **6.26**   | **%**      | 4.72     | %          |
| ***BGE***                                                       | ** ** | ** ** |       |     |       |
| Remarketed floating rate series mortgage bonds                  | ** ** | **—** | **%**      | 3.14     | %          |

 

** As discussed in Note 13, we have entered intointerest rate swaps relating to $450.0 million of our fixed-rate debt.*

**Preference Stock**

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

 ̈  thepreference stock has one vote per share on any charter amendment which wouldcreate or authorize any shares of stock ranking prior to or on a parity withthe preference stock as to either dividends or distribution of assets, or whichwould substantially adversely affect the contract rights, as expressly setforth in BGE’s charter, of the preference stock, each of which requires theaffirmative vote of two-thirds of all the shares of preference stockoutstanding; and

 ̈  wheneverBGE fails to pay full dividends on the preference stock and such failurecontinues for one year, the preference stock shall have one vote per share onall matters, until and unless such dividends shall have been paid in full. Uponliquidation, the holders of the preference stock of each series outstanding areentitled to receive the par amount of their shares and an amount equal to the unpaidaccrued dividends.

 

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**10**Taxes

The components of income tax expense are asfollows:
| ***Year Ended December 31,***        | ** ** | **2006**                                          | ** ** | **2005** | ** ** | **2004** | ** ** |
|-----------------------------------------------------|------------|---------------------------------------------------|------------|----------|------------|----------|------------|
| ** **                                          | ** ** | ***(Dollar amounts in millions)*** | ** ** |
| **Income Taxes**                                    | ** ** | ** **                                        |       |     |       |     |       |
| Current                                             | ** ** | ** **                                        |       |     |       |     |       |
| Federal                                             | ** ** | **$**                                             | **246.3**  |     | $          | 14.3     |       | $ | (4.5 | ) |
| State                                               | ** ** | **37.2**                                          |       | 32.7     |       | 20.5     |       |
| Current taxes charged to expense                    | ** ** | **283.5**                                         |       | 47.0     |       | 16.0     |       |
| Deferred                                            | ** ** | ** **                                        |       |     |       |     |       |
| Federal                                             | ** ** | **50.7**                                          |       | 107.9    |       | 85.4     |       |
| State                                               | ** ** | **23.7**                                          |       | 16.1     |       | 24.2     |       |
| Deferred taxes charged to expense                   | ** ** | **74.4**                                          |       | 124.0    |       | 109.6    |       |
| Investment tax credit adjustments                   | ** ** | **(6.9**                                          | **)**      | (7.1     | )          | (7.2     | )          |
| Income  taxes per Consolidated Statements of Income | ** ** | **$**                                             | **351.0**  |     | $          | 163.9    |       | $ | 118.4 |   |

 

*Certainprior year amounts have been reclassified to conform to the current year’spresentation of discontinued operations.*

Total income taxes are different from theamount that would be computed by applying the statutory Federal income tax rateof 35% to book income before income taxes as follows:
| **Reconciliation of Income Taxes Computed at  Statutory Federal Rate to Total Income Taxes**      | ** ** | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|------------|-------------|------------|------------|------------|------------|
| Income from continuing operations before  income taxes (excluding BGE preference stock dividends) | ** ** | **$**      | **1,112.8** |       | $          | 713.0      |       | $ | 630.0 |   |
| Statutory federal income tax rate                                                                 | ** ** | **35%**    |        | 35%        |       | 35%        |       |
| Income taxes computed at statutory federal  rate                                                  | ** ** | **389.5**  |        | 249.5      |       | 220.5      |       |
| Increases (decreases) in income taxes due  to                                                     |       |       |        |       |       |       |       |
| Depreciation differences not normalized on  regulated activities                                  | ** ** | **3.6**    |        | 3.8        |       | 4.0        |       |
| Amortization of deferred investment tax  credits                                                  | ** ** | **(6.9**   | **)**       | (7.1       | )          | (7.2       | )          |
| Synthetic fuel tax credits flowed through  to income*                                             | ** ** | **(120.2** | **)**       | (114.9     | )          | (123.2     | )          |
| Estimated synthetic fuel tax credit  phase-out                                                    | ** ** | **44.3**   |        | —     |       | —     |       |
| State income taxes, net of federal income  tax benefit                                            | ** ** | **42.6**   |        | 31.5       |       | 28.2       |       |
| Merger-related transaction costs                                                                  | ** ** | **(5.3**   | **)**       | 5.3        |       | —     |       |
| Other                                                                                             | ** ** | **3.4**    |        | (4.2       | )          | (3.9       | )          |
| Total income taxes                                                                                | ** ** | **$**      | **351.0**   |       | $          | 163.9      |       | $ | 118.4 |   |
| Effective income tax rate                                                                         | ** ** | **31.5%**  |        | 23.0%      |       | 18.8%      |       |

 

*Certain prior year amounts havebeen reclassified to conform to the current year’s presentation of discontinuedoperations.*

** 2004 includes credits associated with 2003production at our South Carolina facility that were recognized in the second quarterof 2004 upon receipt of a favorable Private Letter Ruling from the IRS.*

BGE’s effective tax rate was 37.5% in 2006, 38.8% in 2005, and 38.1% in2004. The difference between BGE’s effective tax rate and the 35% statutoryfederal income tax rate is primarily related to Maryland corporate income taxesat an effective rate of 4.6%, which is net of the related federal income taxbenefit. In 2006, this is partially offset by deducting merger-related costsincurred in 2005 as a result of the termination of the merger with FPL Group(0.5%) and the taking of an employee savings plan dividend deduction (0.5%).

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The major components of our net deferred income tax liability are asfollows:
| *** ***                                            | ** ** | **Constellation Energy** | ** **  | **BGE**    | ** ** |
|---------------------------------------------------------|------------|-------------------------------|-------------|------------|------------|
| ***At December 31,***                         | ** ** | **2006**                      | ** **  | **2005**   | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                              | ** ** | ***(In millions)***      | ** **  |
| **Deferred  Income Taxes**                              |       | ** **                    | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Deferred tax liabilities                                |       | ** **                    | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net property, plant and equipment                       | ** ** | **$**                         | **1,539.1** | ** ** | $          | 1,539.3 | ** ** | **$** | **524.2** |   | $ | 526.7 |   |
| Qualified nuclear decommissioning trust funds           | ** ** | **339.5**                     | ** **  | 332.8      | ** ** | **—** |   | — |   |
| Regulatory assets, net                                  | ** ** | **203.3**                     | ** **  | 85.5       | ** ** | **203.3** |   | 85.5 |   |
| Mark-to-market energy assets and liabilities, net       | ** ** | **154.7**                     | ** **  | 141.2      | ** ** | **—** |   | — |   |
| Other                                                   | ** ** | **145.6**                     | ** **  | 112.7      | ** ** | **72.7** |   | 61.3 |   |
| Total deferred tax liabilities                          | ** ** | **2,382.2**                   | ** **  | 2,211.5    | ** ** | **800.2** |   | 673.5 |   |
| Deferred tax assets                                     |       | ** **                    | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Asset retirement obligation                             | ** ** | **384.6**                     | ** **  | 353.6      | ** ** | **—** |   | — |   |
| Defined benefit obligations                             | ** ** | **351.1**                     | ** **  | 243.8      | ** ** | **39.8** |   | 41.4 |   |
| Financial investments and hedging instruments           | ** ** | **757.2**                     | ** **  | 144.7      | ** ** | **—** |   | — |   |
| Deferred investment tax credits                         | ** ** | **22.1**                      | ** **  | 24.2       | ** ** | **4.7** |   | 5.3 |   |
| Reduction of investments                                | ** ** | **7.3**                       | ** **  | 7.4        | ** ** | **—** |   | — |   |
| Other                                                   | ** ** | **98.4**                      | ** **  | 105.6      | ** ** | **10.6** |   | 8.3 |   |
| Total deferred tax assets                               | ** ** | **1,620.7**                   | ** **  | 879.3      | ** ** | **55.1** |   | 55.0 |   |
| Total deferred tax liability, net                       | ** ** | **761.5**                     | ** **  | 1,332.2    | ** ** | **745.1** |   | 618.5 |   |
| Less: Current portion of deferred tax (asset)/liability | ** ** | **(674.3**                    | **)**       | 151.4      | ** ** | **47.4** |   | 9.6 |   |
| Long-term  portion of deferred tax liability, net       | ** ** | **$**                         | **1,435.8** | ** ** | $          | 1,180.8 | ** ** | **$** | **697.7** |   | $ | 608.9 |   |

 

*Certain prior year amounts have beenreclassified to conform to the current year’s presentation.*

**Synthetic Fuel Tax Credits**

Our merchantenergy business has investments in facilities that manufacture solid syntheticfuel produced from coal as defined under the Internal Revenue Code (IRC) forwhich we can claim tax credits on our Federal income tax return through 2007.We recognize the tax benefit of these credits in our Consolidated Statements ofIncome when we believe it is highly probable that the credits will besustained. The synthetic fuel process involves combining coal material with achemical reagent to create a significant chemical change. A taxpayer mayrequest a private letter ruling from the IRS to support its position that thesynthetic fuel produced undergoes a significant chemical change and thusqualifies for synthetic fuel tax credits.

We own aminority ownership in four synthetic fuel facilities located in Virginia andWest Virginia. These facilities have received private letter rulings from theIRS. In 2004, the IRS concluded its examination of the partnership that ownsthese facilities for the tax years 1998 through 2001 and the IRS did notdisallow any of the previously recognized synthetic fuel credits.

In 2003, wepurchased 99% ownership in a South Carolina facility that produces syntheticfuel. We did not recognize in our Consolidated Statements of Income the taxbenefit of $35.9 million for credits claimed on our South Carolinafacility in 2003 pending receipt of a favorable private letter ruling. In 2004,we received a favorable private letter ruling. We believe receipt of theprivate letter ruling provides reasonable assurance that it is highly probablethat the credits will be sustained. Therefore, we recognized the tax benefit of$35.9 million in our Consolidated Statements of Income during 2004. In2006, the IRS concluded its examination of the partnership that owns the SouthCarolina facility for the 2003 and 2004 tax years and the IRS did not disallowany of the previously recognized synthetic fuel credits.

The IRCprovides for a phase-out of synthetic fuel tax credits if average annualwellhead oil prices increase above certain levels. To determine the amount ofthe phase-out, we are required to compare average annual wellhead oil pricesper barrel as published by the IRS (reference price) to a Gross NationalProduct inflation adjusted oil price for the year, also published by the IRS. Thereference price is determined based on wellhead prices for all domestic oilproduction as published by the Energy Information Administration (EIA). For2006, we estimate the tax credit reduction would begin if the reference priceexceeds approximately $55 per barrel and would be fully phased out if thereference price exceeds approximately $68 per barrel.

Based onmonthly EIA published wellhead oil prices for the ten months ended October 31,2006 and November and December NYMEX prices for light, sweet, crude oil(adjusted for the 2006 difference between EIA and NYMEX prices), we estimate a38% tax credit phase-out in 2006. We recorded the effect of this phase-outestimate as a reduction in tax credits of $44.3 million during 2006.

Based onforward market prices and volatilities as of February 22, 2007, weestimate a 21% tax credit phase-out for the year 2007. The expected amount ofsynthetic fuel tax credits phased-out may change materially from period toperiod as a result of continued changes in oil prices.

While we believe the production and sale of synthetic fuel from all ofour synthetic fuel facilities meet the conditions to qualify for tax creditsunder the IRC, we cannot predict the timing or outcome of any future challengeby the IRS, legislative or regulatory action, or the ultimate impact of suchevents on the synthetic fuel tax credits that we have claimed to date, but theimpact could be material to our financial results.

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**Income Tax Audits**

Ourconsolidated federal income tax returns for the for the tax years  2002 through 2004 are currently underexamination by the IRS. Our consolidated federal income tax returns for the2001 and prior tax years are closed under the statute of limitations. Incometax returns filed in other jurisdictions are also subject to audit foradditional tax periods. Although the final outcome of current and future taxaudits is uncertain, we believe that adequate provisions for income taxes havebeen made for potential liabilities resulting from such matters.

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**11** Leases

There are two types of leases—operating and capital. Capital leasesqualify as sales or purchases of property and are reported in our ConsolidatedBalance Sheets. Our capital leases are not material in amount. All other leasesare operating leases and are reported in our Consolidated Statements of Income.We expense all lease payments associated with our regulated business. Leaseexpense and future minimum payments for long-term, noncancelable, operatingleases are not material to BGE’s financial results. We present informationabout our operating leases below.

**Outgoing LeasePayments**

We, as lessee, lease some facilities and equipment. The leaseagreements expire on various dates and have various renewal options. We alsoenter into certain power purchase agreements which are accounted for asoperating leases. Under these agreements, we are required to make fixedcapacity payments, as well as variable payments based on actual output of theplants. We record these payments as “Fuel and purchased energy expenses” in ourConsolidated Statements of Income. We exclude from our future minimum leasepayments table the variable payments related to the output of the plant due tothe contingency associated with these payments.

We recognized expense related to ouroperating leases as follows:
| ** ** | ** ** | **Fuel and  purchased  energy  expenses** | ** ** | **Operating  expenses** | ** ** | **Total** | ** ** |
|------------|------------|------------------------------------------------|------------|-------------------------|------------|-----------|------------|
| ** ** | ** ** | ***(In millions)***                       | ** ** |
| 2006       |       |                                           | $          | 162.6                   |       |      |       | $ | 24.7 |   |   | $ | 187.3 |   |
| 2005       |       |                                           | 103.2      |                    |       |      | 24.8       |   |   | 128.0 |   |
| 2004       |       |                                           | 11.0       |                    |       |      | 23.1       |   |   | 34.1 |   |
|            |            |                                                |            |                         |            |           |            |  |  |  |  |  |  |  |

 

At December 31, 2006, we owed futureminimum payments for long-term, noncancelable, operating leases as follows:
| ***Year***                          | ** ** | **Power  Purchase  Agreements** | ** ** | **Other** | ** ** | **Total** | ** ** |
|-------------------------------------|------------|---------------------------------|------------|-----------|------------|-----------|------------|
| ** **                          | ** ** | ***(In millions)***        | ** ** |
| 2007                                |       |                            | $          | 162.0     |       |      | $          | 24.0 |   | $ | 186.0 |   |
| 2008                                |       |                            | 121.5      |      |       | 19.6      |       | 141.1 |   |
| 2009                                |       |                            | 62.3       |      |       | 18.9      |       | 81.2 |   |
| 2010                                |       |                            | 59.4       |      |       | 17.8      |       | 77.2 |   |
| 2011                                |       |                            | 59.3       |      |       | 16.9      |       | 76.2 |   |
| Thereafter                          |       |                            | 317.8      |      |       | 73.8      |       | 391.6 |   |
| Total future minimum lease payments |       |                            | $          | 782.3     |       |      | $          | 171.0 |   | $ | 953.3 |   |

 

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**12**Commitments, Guarantees, and Contingencies

**Commitments**

We have made substantial commitments in connection with our merchantenergy, regulated electric and gas, and other nonregulated businesses. Thesecommitments relate to:

 ̈  purchaseof electric generating capacity and energy,

 ̈  procurementand delivery of fuels,

 ̈  thecapacity and transmission and transportation rights for the physical deliveryof energy to meet our obligations to our customers, and

 ̈  long-termservice agreements, capital for construction programs, and other.

Our merchantenergy business enters into various long-term contracts for the procurement anddelivery of fuels to supply our generating plant requirements. In most cases,our contracts contain provisions for price escalations, minimum purchaselevels, and other financial commitments. These contracts expire in variousyears between 2007 and 2020. In addition, our merchant energy business entersinto long-term contracts for the capacity and transmission rights for thedelivery of energy to meet our physical obligations to our customers. Thesecontracts expire in various years between 2007 and 2019.

Our merchantenergy business also has committed to long-term service agreements and otherpurchase commitments for our plants.

Our regulatedelectric business enters into various long-term contracts for the procurementof electricity. These contracts expire between 2007 and 2009. As discussed in *Note 1,*the cost of power under thesecontracts is fully recoverable, and therefore is excluded from the table on thenext page.

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Our regulatedgas business enters into various long-term contracts for the procurement,transportation, and storage of gas. Our regulated gas business has gastransportation and storage contracts that expire between 2007 and 2028. Thesecontracts are recoverable under BGE’s gas cost adjustment clause discussed in *Note 1,* and therefore are excludedfrom the table below.

Our othernonregulated businesses have committed to gas purchases and to contributions ofadditional capital for construction programs and joint ventures in which theyhave an interest.

We have alsocommitted to long-term service agreements and other obligations related to ourinformation technology systems.

At December 31, 2006, we estimate ourfuture obligations to be as follows:
| ** **                                        | ** ** | **Payments**             | ** ** | ** **      | ** ** |
|---------------------------------------------------|------------|--------------------------|------------|-----------------|------------|
| ** **                                        | ** ** | **2007**                 | ** ** | **2008-  2009** | ** ** | **2010-  2011** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
| ** **                                        | ** ** | ***(In millions)*** | ** ** |
| Merchant Energy:                                  |       |                     |       |            |       |   |   |   |   |   |   |   |   |
| Purchased capacity  and energy               |       | $                        | 367.1      |            | $          | 755.5 |   | $ | 271.8 |   |   | $ | 526.0 |   |   | $ | 1,920.4 |   |
| Fuel and transportation                           |       | 2,866.5                  |       | 1,867.3         |       | 475.9 |   |   | 894.4 |   |   | 6,104.1 |   |
| Long-term service  agreements, capital, and other |       | 15.8                     |       | 10.1            |       | 5.5 |   |   | 23.9 |   |   | 55.3 |   |
| Total merchant energy                             |       | 3,249.4                  |       | 2,632.9         |       | 753.2 |   |   | 1,444.3 |   |   | 8,079.8 |   |
| Corporate and Other:                              |       |                     |       |            |       |   |   |   |   |   |   |   |   |
| Long-term service  agreements, capital, and other |       | 33.0                     |       | 17.0            |       | 4.1 |   |   | — |   |   | 54.1 |   |
| Regulated:                                        |       |                     |       |            |       |   |   |   |   |   |   |   |   |
| Purchase obligations and  other                   |       | 54.4                     |       | 40.9            |       | — |   |   | 2.2 |   |   | 97.5 |   |
| Total future obligations                          |       | $                        | 3,336.8    |            | $          | 2,690.8 |   | $ | 757.3 |   |   | $ | 1,446.5 |   |   | $ | 8,231.4 |   |

 

***Termination ofMerger Agreement with FPL Group, Inc.***

In connection with the termination of the merger agreement with FPLGroup, there are certain contingencies relating to potential cash payments. Wediscuss these contingencies in *Note 15*.

**Long-Term PowerSales Contracts**

We enter into long-term power sales contracts in connection with ourload-serving activities. We also enter into long-term power sales contractsassociated with certain of our power plants. Our load-serving power salescontracts extend for terms through 2019 and provide for the sale of energy toelectricity distribution utilities and certain retail customers. Our powersales contracts associated with our power plants extend for terms into 2014 andprovide for the sale of all or a portion of the actual output of certain of ourpower plants. All long-term contracts were executed at pricing thatapproximated market rates, including profit margin, at the time of execution.

**Guarantees**

Our guarantees do not represent incrementalConstellation Energy Group obligations; rather they primarily representparental guarantees of subsidiary obligations. The following table summarizesthe maximum exposure based on the stated limit of our outstanding guarantees atDecember 31, 2006:
| ***At December 31, 2006*** | ** ** | **Stated Limit**    | ** ** |
|-------------------------------------------|------------|--------------------------|------------|
| ** **                                | ** ** | ***(In millions)*** | ** ** |
| Competitive supply guarantees             |       |                     | $          | 10,001.8 |   |   |
| Nuclear guarantees                        |       |                     | 917.8      |   |   |
| BGE guarantees                            |       |                     | 263.3      |   |   |
| Other non-regulated guarantees            |       |                     | 75.2       |   |   |
| Power project guarantees                  |       |                     | 19.2       |   |   |
| Total guarantees                          |       |                     | $          | 11,277.3 |   |   |

 

At December 31, 2006, Constellation Energy had a total of$11,277.3 million in guarantees in outstanding related to loans, creditfacilities, and contractual performance of certain of its subsidiaries asdescribed below.

 ̈  ConstellationEnergy guaranteed $10,001.8 million on behalf of our subsidiaries forcompetitive supply activities. These guarantees are put into place in order toallow our subsidiaries the flexibility needed to conduct business withcounterparties without having to post other forms of collateral. While the faceamount of these guarantees is $10,001.8 million, our calculated fair valueof obligations for commercial transactions covered by these guarantees was$2,190.6 million at December 31, 2006. If the parent company wasrequired to fund these subsidiary obligations, the total amount based on December 31,2006 market prices would be $2,190.6 million. For those guarantees relatedto our mark-to-market energy or risk management liabilities, the fair value ofthe obligation is recorded in our Consolidated Balance Sheets.

 ̈  ConstellationEnergy guaranteed $917.8 million primarily on behalf of our nucleargenerating facilities mostly due to nuclear insurance and for credit support toensure these plants have funds to meet expenses and obligations to safelyoperate and maintain the plants.

 ̈  BGEguaranteed the Trust Preferred Securities of $250.0 million of BGE TrustII, an unconsolidated investment, as discussed in *Note 9*.

 ̈  BGEguaranteed two-thirds of certain debt of Safe Harbor Water Power Corporation,an unconsolidated investment. At December 31, 2006, Safe Harbor WaterPower Corporation had outstanding debt of $20.0 million. The maximumamount of BGE’s guarantee is $13.3 million.

 ̈  ConstellationEnergy guaranteed $62.7 million on behalf of our other nonregulatedbusinesses primarily for loans and performance bonds of which$25.0 million was recorded in our Consolidated Balance Sheets at December 31,2006.

 ̈  Ourother nonregulated business guaranteed $12.5 million primarily forperformance bonds.

 ̈  Ourmerchant energy business guaranteed $19.2 million for loans and otherperformance guarantees related to certain power projects in which we have aninvestment.

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We believe it is unlikely that we would be required to perform or incurany losses associated with guarantees of our subsidiaries’ obligations.

**Contingenies**

**Revenue SufficiencyGuarantee Costs**

In April 2006,the FERC issued an order requiring the Midwest Independent System Operator(MISO) to retroactively re-allocate revenue sufficiency guarantee costs (RSGs)for the period April 2005 to present based on the FERC’s finding that MISOviolated its tariff and incorrectly allocated RSGs among market participants.The re-allocation of RSGs would result in some participants recognizingadditional expense and others receiving refunds.

In May 2006,the MISO filed a motion with FERC seeking a stay of the FERC order. The motionwas granted by FERC delaying the implementation of the original order untilafter the issuance of an order on rehearing. In May 2006, we and othermarket participants filed requests for rehearing with FERC.

In October 2006, FERC issued an order on rehearing that reversedthe original retroactive re-allocation of RSGs. Based on this order we estimatethe impact of the RSG re-allocation, if any, to be immaterial to our financialresults. However, further requests for rehearing and appeals have beensubmitted and we cannot predict the ultimate timing or outcome of any suchaction.

**EnvironmentalMatters**

*Solid andHazardous Waste*

The Environmental Protection Agency (EPA) and several state agencieshave notified us that we are considered a potentially responsible party withrespect to the clean-up of certain environmentally contaminated sites. Wecannot estimate the final clean-up costs for all of these sites, but thecurrent estimated costs for, and current status of, each site is described inmore detail below.

*68th StreetDump*

In 1999, the EPA proposed to add the 68th Street Dump in Baltimore,Maryland to the Superfund National Priorities List, which is its list of sitestargeted for clean-up and enforcement, and sent a general notice letter to BGEand 19 other parties identifying them as potentially liable parties at thesite. In March 2004, we and other potentially responsible parties formedthe 68th Street Coalition and entered into consent order negotiations with theEPA to investigate clean-up options for the site under the SuperfundAlternative Sites Program. In May 2006, a settlement among the EPA and 19of the potentially responsible parties, including BGE, with respect toinvestigation of the site became effective. The settlement requires thepotentially responsible parties, over the course of several years, to identifycontamination at the site and recommend clean-up options. BGE is fullyindemnified by a wholly-owned affiliate of Constellation Energy for costsrelated to this settlement, as well as any clean-up costs. The clean-upcosts will not be known until the investigation is closer to completion.However, those costs could have a material effect on our financial results.

*Kane and Lombard*

The EPA issued its record of decision for the Kane and Lombard Drumsite located in Baltimore, Maryland on September 30, 2003, which specifiedthe clean-up plan for the site, consisting of enhanced reductivedechlorination, a soil management plan, and institutional controls. An EPAorder requiring cleanup of the site by 18 parties, including ConstellationEnergy, became effective in November 2006. The EPA estimates that totalclean-up costs will be approximately $7 million. Our share of site-relatedcosts will be 11.1% of the total. We recorded a liability in our ConsolidatedBalance Sheets for our share of the clean-up costs that we believe is probable.

*Spring Gardens*

In December 1996,BGE signed a consent order with the Maryland Department of the Environment thatrequires it to implement remedial action plans for contamination at and aroundthe Spring Gardens site, located in Baltimore, Maryland. The Spring Gardenssite was once used to manufacture gas from coal and oil. Based on remedialaction plans and cost modeling performed in late 2006, BGE estimates itsprobable clean-up costs will total $43 million. BGE has recorded thesecosts as a liability in its Consolidated Balance Sheets and has deferred thesecosts, net of accumulated amortization and amounts it recovered from insurancecompanies, as a regulatory asset. Based on the results of studies at this site,it is reasonably possible that additional costs could exceed the amount BGE hasrecognized by approximately $3 million. Through December 31, 2006,BGE has spent approximately $40 million for remediation at this site.

BGE also has investigated other small sites where gas was manufacturedin the past. We do not expect the clean-up costs of the remaining smaller sitesto have a material effect on our financial results.

*Air Quality*

In late July 2005, we received two Notices of Violation (NOVs)from the Placer County Air Pollution Control District, Placer County California(District) alleging that the Rio Bravo Rocklin facility located in Lincoln, Californiahad violated certain District air emission regulations. We have a combined 50%ownership interest in the partnership which owns the Rio Bravo Rocklinfacility. The NOVs allege a total of 38 violations between January 2003and March 2005 of either the facility’s air permit or federal, state, andcounty air emission standards related to nitrogen oxide, carbon monoxide, andparticulate emissions, as well as violations of certain monitoring andreporting requirements during that time period. The maximum civil penalties forthe alleged violations range from $10,000 to $40,000 per violation. Managementof the Rio Bravo Rocklin facility is currently discussing the allegations inthe NOVs with District representatives. It is not possible to determine the actualliability, if any, of the partnership that owns the Rio Bravo Rocklin facility.

**Litigation**

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

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***Western Power Markets***

*City of Tacoma v. AEP, et al.,**—*The City of Tacoma, on June 7, 2004, in the U.S.District Court, Western District of Washington, filed a complaint against over60 companies, including Constellation Energy Commodities Group, Inc.(CCG). The complaint alleges that the defendants engaged in manipulation ofelectricity markets resulting in prices for power in the western power marketsthat were substantially above what market prices would have been in the absenceof the alleged unlawful contracts, combinations and conspiracy in violation of Section 1of the Sherman Act. The complaint further alleges that the total amount ofdamages is unknown, but is estimated to exceed $175 million. On February 11,2005, the Court granted the defendants’ motion to dismiss the action based onthe Court’s lack of jurisdiction over the claims in question. The plaintiff hasappealed the dismissal of the action to the Ninth Circuit Court of Appeals. Webelieve that we have meritorious defenses to this action and intend to defendagainst it vigorously. However, we cannot predict the timing, or outcome, ofthis case, or its possible effect on our financial results.

***Mercury***

Since September 2002,BGE, Constellation Energy, and several other defendants have been involved innumerous actions filed in the Circuit Court for Baltimore City, Marylandalleging mercury poisoning from several sources, including coal plants formerlyowned by BGE. The plants are now owned by a subsidiary of Constellation Energy.In addition to BGE and Constellation Energy, approximately 11 other defendants,consisting of pharmaceutical companies, manufacturers of vaccines, andmanufacturers of Thimerosal have been sued. Approximately 70 cases, involvingclaims related to approximately 132 children, have been filed to date, witheach claimant seeking $20 million in compensatory damages, plus punitivedamages, from us.

In rulings applicable to all but six of the cases, involving claimsrelated to approximately 50 children, the Circuit Court for Baltimore Citydismissed with prejudice all claims against BGE and Constellation Energy.Plaintiffs may attempt to pursue appeals of the rulings in favor of BGE andConstellation Energy once the cases are finally concluded as to all defendants.We believe that we have meritorious defenses and intend to defend the remainingactions vigorously. However, we cannot predict the timing, or outcome, of thesecases, or their possible effect on our, or BGE’s, financial results.

***Asbestos***

Since 1993, BGEand certain Constellation Energy subsidiaries have been involved in severalactions concerning asbestos. The actions are based upon the theory of “premisesliability,” alleging that BGE and Constellation Energy knew of and exposedindividuals to an asbestos hazard. In addition to BGE and Constellation Energy,numerous other parties are defendants in these cases.

Approximately522 individuals who were never employees of BGE or Constellation Energy havepending claims each seeking several million dollars in compensatory andpunitive damages. Cross-claims and third-party claims brought byother defendants may also be filed against BGE and Constellation Energy inthese actions. To date, most asbestos claims against us have been dismissed orresolved without any payment and a small minority have been resolved for amountsthat were not material to our financial results. The remaining claims arecurrently pending in state courts in Maryland and Pennsylvania.

BGE and Constellation Energy do not know the specific facts necessaryto estimate its potential liability for these claims. The specific facts we donot know include:

 ̈  theidentity of the facilities at which the plaintiffs allegedly worked ascontractors,

 ̈  thenames of the plaintiffs’ employers,

 ̈  thedates on which and the places where the exposure allegedly occurred, and

 ̈  thefacts and circumstances relating to the alleged exposure.

Until the relevant facts are determined, we are unable to estimate whatour, or BGE’s, liability might be. Although insurance and hold harmless agreements from contractors who employedthe plaintiffs may cover a portion of any awards in the actions, the potentialeffect on our, or BGE’s, financial results could be material.

***Storage ofSpent Nuclear Fuel***

The NuclearWaste Policy Act of 1982 (NWPA) required the federal government through theDepartment of Energy (DOE), to develop a repository for, and disposal of, spentnuclear fuel and high-level radioactive waste. The NWPA and our contracts withthe DOE required the DOE to begin taking possession of spent nuclear fuelgenerated by nuclear generating units no later than January 31, 1998. TheDOE has stated that it will not meet that obligation until 2017 at theearliest.

This delay hasrequired that we undertake additional actions related to on-site fuel storageat Calvert Cliffs and Nine Mile Point, including the installation of on-sitedry fuel storage capacity at Calvert Cliffs. In January 2004, we filed acomplaint against the federal government in the United States Court of FederalClaims seeking to recover damages caused by the DOE’s failure to meet itscontractual obligation to begin disposing of spent nuclear fuel by January 31,1998. The case is currently stayed, pending litigation in other related cases.

In connection with our purchase of Ginna, all of Rochester Gas &Electric Corporation’s (RG&E) rights and obligations related to recovery ofdamages for DOE’s failure to meet its contractual obligations were assigned tous. However, we have an obligation to reimburse RG&E for up to$10 million in recovered damages for such claims.

**Nuclear Insurance**

We maintainnuclear insurance coverage for Calvert Cliffs, Nine Mile Point, and Ginna infour program areas: liability, worker radiation, property, and accidentaloutage. These policies contain certain industry standard exclusions, including,but not limited to, ordinary wear and tear, and war.

In November 2002,the President signed into law the Terrorism Risk Insurance Act (“TRIA”) of2002, which was extended by the Terrorism Risk Insurance Extension Act of 2005.Under the TRIA, property and casualty insurance companies are required to offerinsurance for losses resulting 

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from Certified acts of terrorism. Certified acts of terrorism aredetermined by the Secretary of the Treasury, in concurrence with the Secretaryof State and Attorney General, and primarily are based upon the occurrence ofsignificant acts of international terrorism. Our nuclear liability, nuclearproperty and accidental outage insurance programs, as discussed later in thissection, provide coverage for Certified acts of terrorism.

If there were an accident or an extended outage at any unit of CalvertCliffs, Nine Mile Point or Ginna, it could have a substantial adverse impact onour financial results.

*NuclearLiability Insurance*

Pursuant to the Price-Anderson Act, we are required to insureagainst public liability claims resulting from nuclear incidents to the fulllimit of public liability. This limit of liability consists of the maximumavailable commercial insurance of $300 million and mandatory participationin an industry-wide retrospective premium assessment program. The retrospectivepremium assessment is $100.6 million per reactor, increasing the totalamount of insurance for public liability to approximately $10.8 billion.Under the retrospective assessment program, we can be assessed up to$503 million per incident at any commercial reactor in the country,payable at no more than $75 million per incident per year. This assessmentalso applies in excess of our worker radiation claims insurance and is subjectto inflation and state premium taxes. Claims resulting from non-certified actsof terrorism are limited to the commercial insurance discussed above,regardless of the number of nuclear plants affected. In addition, the U.S.Congress could impose additional revenue-raising measures to pay claims.

***WorkerRadiation Claims Insurance***

We participate in the American Nuclear Insurers Master Worker Programthat provides coverage for worker tort claims filed for radiation injuries.Effective January 1, 1998, this program was modified to provide coverageto all workers whose nuclear-related employment began on or after thecommencement date of reactor operations. Waiving the right to make additionalclaims under the old policy was a condition for coverage under the new policy.We describe the old and new policies below:

 ̈  Allnuclear worker claims reported on or after January 1, 1998 are covered bya new insurance policy. The new policy provides a single industry aggregatelimit of $200 million for occurrences of radiation injury claims against allthose insured by this policy prior to January 1, 2003 and$300 million for occurrences of radiation injury claims against all thoseinsured by this policy on or after January 1, 2003.

 ̈  Allnuclear worker claims reported prior to January 1, 1998 are still coveredby the old policy. Insureds under the old policies, with no current operations,are not required to purchase the new policy described above, and may still makeclaims against the old policies through 2007. If radiation injury claims underthese old policies exceed the policy reserves, all policyholders could beretroactively assessed, with our share being up to $6.3 million.

The sellers of Nine Mile Point retain the liabilities for existing andpotential claims that occurred prior to November 7, 2001. In addition, theLong Island Power Authority, which continues to own 18% of Unit 2 at Nine MilePoint, is obligated to assume its pro rata share of any liabilities forretrospective premiums and other premium assessments. RG&E, the seller ofGinna, retains the liabilities for existing and potential claims that occurredprior to June 10, 2004. If claims under these policies exceed the coveragelimits, the provisions of the Price-Anderson Act would apply.

*Nuclear PropertyInsurance*

Our policiesprovide $500 million in primary coverage at each nuclear plant—CalvertCliffs, Nine Mile Point, and Ginna. In addition, we maintain $1.77 billionof excess coverage at Ginna and $2.25 billion in excess coverage under ablanket excess program offered by the industry mutual insurer at both CalvertCliffs and Nine Mile Point. Under the blanket excess policy, Calvert Cliffs andNine Mile Point share $1.0 billion of the total $2.25 billion ofexcess property coverage. Therefore, in the unlikely event of two full limitproperty damage losses at Calvert Cliffs and Nine Mile Point, we would recover$4.5 billion instead of $5.5 billion. This coverage currently ispurchased through the industry mutual insurance company. If accidents at plantsinsured by the mutual insurance company cause a shortfall of funds, allpolicyholders could be assessed, with our share being up to $92.6 million.

Losses resulting from non-certified acts of terrorism are covered as acommon occurrence, meaning that if non-certified terrorist acts occur againstone or more commercial nuclear power plants insured by our nuclear propertyinsurance company within a 12-month period, they would be treated as oneevent and the owners of the plants where the acts occurred would share one fulllimit of liability (currently $3.24 billion).

***AccidentalNuclear Outage Insurance***

Our policies provide indemnification on a weekly basis for lossesresulting from an accidental outage of a nuclear unit. Coverage begins after a12-week deductible period and continues at 100% of the weekly indemnitylimit for 52 weeks and then 80% of the weekly indemnity limit for the next 110 weeks.Our coverage is up to $490.0 million per unit at Calvert Cliffs and Ginna,$420.0 million for Unit 1 of Nine Mile Point, and $401.8 million forUnit 2 of Nine Mile Point. This amount can be reduced by up to$98.0 million per unit at Calvert Cliffs and $84.0 million for NineMile Point if an outage of more than one unit is caused by a single insuredphysical damage loss.

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*Non-NuclearProperty Insurance*

Our conventional property insurance provides coverage of$1.0 billion per occurrence for Certified acts of terrorism as definedunder TRIA and Terrorism Risk Insurance Extension Act of 2005. Certified actsof terrorism are determined by the Secretary of the Treasury, in concurrencewith the Secretary of State and Attorney General, and primarily are based uponthe occurrence of significant acts of international terrorism. Our conventionalproperty insurance program also provides coverage for non-certified acts ofterrorism up to an annual aggregate limit of $1.0 billion. If a terroristact occurs at any of our facilities, it could have a significant adverse impacton our financial results.

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**13**HedgingActivities and Fair Value of Financial Instruments

**SFAS No. 133Hedging Activities**

We are exposed to market risk, including changes in interest rates andthe impact of market fluctuations in the price and transportation costs ofelectricity, natural gas, and other commodities.

***CommodityPrices***

*Merchant EnergyBusiness*

Our merchant energy business uses a variety of derivative andnon-derivative instruments to manage the commodity price risk of ourcompetitive supply activities and our electric generation facilities, includingpower sales, fuel and energy purchases, gas purchased for resale, emissioncredits, weather risk, and the market risk of outages. In order to manage theserisks, we may enter into fixed-price derivative or non-derivativecontracts to hedge the variability in future cash flows from forecasted salesof energy and purchases of fuel and energy. The objectives for entering intosuch hedges include:

 ̈  fixing the price for a portion of anticipated futureelectricity sales at a level that provides an acceptable return on our electricgeneration operations,

 ̈  fixing the price of a portion of anticipated fuelpurchases for the operation of our power plants,

 ̈  fixing the price for a portion of anticipated energypurchases to supply our load-serving customers, and

 ̈  fixing the price for a portion of anticipated salesof natural gas to customers.

The portion offorecasted transactions hedged may vary based upon management’s assessment ofmarket, weather, operational, and other factors.

At December 31,2006, our merchant energy business had designated certain fixed-priceforward contracts as cash-flow hedges of forecasted sales of energy andforecasted purchases of fuel and energy for the years 2007 through 2015 underSFAS No. 133. Our merchant energy business had net unrealized pre-taxlosses on these cash-flow hedges recorded in “Accumulated other comprehensiveincome” of $2,227.1 million at December 31, 2006 and $517.1 millionat December 31, 2005.

We expect toreclassify $1,522.1 million of net pre-tax losses on cash-flow hedges from“Accumulated other comprehensive income” into earnings during the next twelvemonths based on the market prices at December 31, 2006. However, theactual amount reclassified into earnings could vary from the amounts recordedat December 31, 2006, due to future changes in market prices.Additionally, for cash-flow hedges settled by physical delivery of theunderlying commodity, “Reclassification of net gains on hedging instrumentsfrom OCI to net income” represents the fair value of those derivatives, whichis realized through gross settlement at the contract price. We recognized intoearnings $13.4 million pre-tax gain in 2006 and $19.4 million pre-tax loss in2005 related to cash-flow hedge ineffectiveness.

In addition,during 2006, we de-designated contracts previously designated as cash-flowhedges for which the forecasted transaction originally hedged is probable ofnot occurring, and as a result we recognized a pre-tax loss of$35.3 million. The majority of the pre-tax loss associated with de-designatedcontracts in 2006 resulted from the initial public offering of CEP and the saleof our gas-fired plants. During 2005, we terminated a contract previouslydesignated as a cash-flow hedge. The forecasted transaction originally hedged wasprobable of not occurring and as a result we recognized a pre-tax loss of$6.1 million.

Our merchant energy business also enters into natural gas storagecontracts under which the gas in storage qualifies for fair value hedgeaccounting treatment under SFAS No. 133. We recognized a $27.7 millionpre-tax net gain for 2006 and $2.2 million pre-tax net loss for 2005 dueto hedge ineffectiveness. In addition, we recognized an $8.9 million pre-taxgain related to the change in value for the portion of our fair value hedgesexcluded from ineffectiveness testing. We record changes in fair value of thesehedges related to our retail competitive supply operations as a component of “Fueland purchased energy expenses” in our Consolidated Statements of Income. We recordchanges in fair value of these hedges related to our wholesale competitivesupply operations as a component of “Nonregulated revenues” in our ConsolidatedStatements of Income.

*Regulated GasBusiness*

BGE uses basis swaps in the winter months (November through March)to hedge its price risk associated with natural gas purchases under its market-basedrates incentive mechanism and under its off-system gas sales program. BGE alsouses fixed-to-floating and floating-to-fixed swaps to hedge its price risk associatedwith its off-system gas sales. The fixed portion represents a specific dollaramount that BGE will pay or receive, and the floating portion represents afluctuating amount based on a published index that BGE will receive or pay. BGE’sregulated gas business internal guidelines do not permit the use of swapagreements for any purpose other than to hedge price risk. The impact of theseswaps on our, and BGE’s, financial results is immaterial.

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*RegulatedElectric Business*

BGE uses basis swaps to hedge its price risk associated withelectricity purchases. BGE’s regulated electric business internal guidelines donot permit the use of swap agreements for any purpose other than to hedge pricerisk. The impact of these swaps on our, and BGE’s, financial results isimmaterial.

***Interest Rates***

We use interestrate swaps to manage our interest rate exposures associated with new debtissuances, to manage our exposure to fluctuations in interest rates on variablerate debt, and to optimize the mix of fixed and floating-rate debt. The swapsused to manage our exposure prior to the issuance of new debt and to manage theexposure to fluctuations in interest rates on variable rate debt are designatedas cash-flow hedges under SFAS No. 133, with the effective portion ofgains and losses, net of associated deferred income tax effects, recorded in “Accumulatedother comprehensive income” in our Consolidated Statements of CommonShareholders’ Equity and Comprehensive Income and Consolidated Statements ofCapitalization, in anticipation of planned financing transactions. Wereclassify gains and losses on the hedges from “Accumulated other comprehensiveincome” into “Interest expense” in our Consolidated Statements of Income duringthe periods in which the interest payments being hedged occur.

The swaps usedto optimize the mix of fixed and floating-rate debt are designated as fairvalue hedges under SFAS No. 133. We record any gains or losses on swapsthat qualify for fair value hedge accounting treatment, as well as changes inthe fair value of the debt being hedged, in “Interest expense,” and we recordany changes in fair value of the swaps and the debt in “Risk management assetsand liabilities” and “Long-term debt” in our Consolidated Balance Sheets. Inaddition, we record the difference between interest on hedged fixed-rate debtand floating-rate swaps in “Interest expense” in the periods that the swapssettle.

“Accumulatedother comprehensive income” includes net unrealized pre-tax gains on interestrate cash-flow hedges terminated upon debt issuance totaling $12.5 million at December 31,2006 and $15.4 million at December 31, 2005. We expect to reclassify$0.6 million of pre-tax net gains on these cash-flow hedges from “Accumulatedother comprehensive income” into “Interest expense” during the next twelvemonths. We had no hedge ineffectiveness on these swaps.

During 2006, inorder to manage the exposure to fluctuations in interest rates on variable ratedebt, CEP entered into a pay fixed-rate and receive floating-rate swap relatingto $16.5 million of its outstanding debt. “Accumulated other comprehensiveincome” includes net unrealized pre-tax gains on interest rate cash-flow hedgestotaling $0.1 million at December 31, 2006. We had no hedgeineffectiveness on these swaps.

During 2004, to optimize the mix of fixed and floating-rate debt, weentered into interest rate swaps qualifying as fair value hedges relating to$450 million of our fixed-rate debt maturing in 2012 and 2015, andconverted this notional amount of debt to floating-rate. The fair value ofthese hedges was an unrealized loss of $7.1 million at December 31, 2006and $0.9 million at December 31, 2005 and was recorded as an increasein our “Risk management liabilities” and a decrease in our “Long-term debt.” Wehad no hedge ineffectiveness on these interest rate swaps.

**Fair Value ofFinancial Instruments**

The fair value of a financial instrument represents the amount at whichthe instrument could be exchanged in a current transaction between willingparties, other than in a forced sale or liquidation. Significant differencescan occur between the fair value and carrying amount of financial instrumentsthat are recorded at historical amounts. We use the following methods andassumptions for estimating fair value disclosures for financial instruments:

 ̈  cash and cash equivalents, net accounts receivable,other current assets, certain current liabilities, short-term borrowings,current portion of long-term debt, and certain deferred credits and otherliabilities: because of their short-term nature, the amounts reported in ourConsolidated Balance Sheets approximate fair value,

 ̈  investments and other assets: the fair value is basedon quoted market prices where available, and

 ̈  long-term debt: the fair value is based on quotedmarket prices where available or by discounting remaining cash flows at currentmarket rates.

We show the carrying amounts and fair valuesof financial instruments included in our Consolidated Balance Sheets in thefollowing table.

| *At December 31,*                            | ** ** | **2006**                 | ** **  | **2005**        | ** ** |
|--------------------------------------------------------|------------|--------------------------|-------------|-----------------|------------|
| ** **                                             | ** ** | **Carrying  Amount**     | ** **  | **Fair  Value** | ** ** | **Carrying  Amount** | ** ** | **Fair  Value** | ** ** |
| ** **                                             | ** ** | ***(In millions)*** | ** **  |
| Investments and other assets—Constellation Energy | ** ** | **$**                    | **1,468.8** | ** **      | **$**      | **1,469.3** |   | $ | 1,362.1 |   | $ | 1,362.3 |   |
| Fixed-rate long-term debt:                             | ** ** | ** **               | ** **  | ** **      |       |   |   |   |   |
| Constellation  Energy                                  | ** ** | **4,383.8**              | ** **  | **4,513.8**     |       | 4,169.3 |   | 4,379.3 |   |
| BGE                                                    | ** ** | **1,716.7**              | ** **  | **1,712.6**     |       | 1,364.6 |   | 1,376.4 |   |
| Variable-rate long-term debt:                          | ** ** | ** **               | ** **  | ** **      |       |   |   |   |   |
| Constellation  Energy                                  | ** ** | **723.2**                | ** **  | **723.2**       |       | 699.3 |   | 699.3 |   |
| BGE                                                    | ** ** | **—**               | ** **  | **—**      |       | 97.4 |   | 97.4 |   |
|                                                        |            |                          |             |                 |            |  |  |  |  |  |  |  |  |

 

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**14**Stock-BasedCompensation

Under our long-term incentive plans, we granted stock options,performance and service-based restricted stock, performance-based units,and equity to officers, key employees, and members of the Board of Directors.Under the plans, we can grant up to a total of 18,000,000 shares. At December 31,2006, we had stock options, restricted stock, performance unit and equitygrants outstanding as discussed below. We may issue new shares, reuse forfeitedshares, or buy shares in the market in order to deliver shares to employees forour equity grants. BGE officers and key employees participate in our stock-basedcompensation plans. The expense recognized by BGE in 2006, 2005, and 2004 wasnot material to BGE’s financial results.

**Non-Qualified Stock Options**

Options are granted with an exercise price equal to the market value ofthe common stock at the date of grant, become vested over a period up to threeyears (expense recognized in tranches), and expire ten years from the date ofgrant. The fair value of our stock-based awards were estimated as of thedate of grant using the Black-Scholes option pricing model based on thefollowing weighted- average assumptions:
| ****                                     | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Risk-free interest rate                  | ** ** |     | **—** |     |       | 4.10     | %          | 3.15 | % |
| Expected life (in years)                 | ** ** |     | **—** |     |       | 2.9      | *          | 5.0 |   |
| Expected market price  volatility factor | ** ** |     | **—** |     |       | 21.3     | %          | 23.7 | % |
| Expected dividend yield                  | ** ** |     | **—** |     |       | 3.0      | %          | 3.0 | % |

 

** Includes 2.0 million fully vested optionsgranted in December 2005, which would have been cancelled upon achange in control if our proposed merger with FPL Group would have beenconsummated and for which an expected life of one year was used to value thegrant. Excluding this grant, we used a weighted-average expected lifeassumption of 5 years for 2005 grants.*

During 2006, no stock options were granted to employees in anticipationof the proposed merger with FPL Group, which was terminated in October 2006.We discuss the termination of the merger in more detail in *Note 15*.

We use the historical data related to stock option exercises in orderto estimate the expected life of our stock options. We also use historical datain order to estimate the volatility factor (measured on a daily basis) for aperiod equal to the duration of the expected life of option awards. We believethat the use of historical data to estimate these factors provides a reasonablebasis for our assumptions. The risk-free interest rate for the periods withinthe expected life of the option is based on the U.S Treasury yield curve ineffect and the expected dividend yield is based on our current estimate fordividend payout at the time of grant. We disclose the pro-forma effect on netincome and earnings per share for the periods prior to adoption of SFAS No. 123Rin *Note 1*.

Summarized information for our stock option grants is as follows:

 
| ** **                                                                                          | ** ** | **2006**                              | ** ** | **2005**                                    | ** ** | **2004**   | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|---------------------------------------------|------------|------------|------------|
| ** **                                                                                          | ** ** | **Shares**                            | ** ** | **Weighted-  Average  Exercise Price** | ** ** | **Shares** | ** ** | **Weighted-  Average  Exercise Price** | ** ** | **Shares** | ** ** | **Weighted-  Average  Exercise Price** | ** ** |
| ** **                                                                                          | ** ** | ***(Shares in thousands)*** | ** ** |
| Outstanding, beginning of year                                                                      | ** ** | **7,172**                             | ** ** |                                        | **$**      | **45.24**  |       |   | 7,365 |   |   | $ | 31.62 |   |   | 7,117 |   |   | $ | 29.53 |   |   |
| Granted with exercise prices at fair market value                                                   | ** ** | **—**                            | ** ** |                                        | **—** |       |       | 3,840 |   |   | 54.94 |   |   | 1,640 |   |   | 39.60 |   |   |
| Exercised                                                                                           | ** ** | **(1,050**                            | **)**      |                                        | **33.77**  |       |       | (3,935 | ) |   | 29.32 |   |   | (834 | ) |   | 28.49 |   |   |
| Forfeited/expired                                                                                   | ** ** | **(71**                               | **)**      |                                        | **45.22**  |       |       | (98 | ) |   | 42.19 |   |   | (558 | ) |   | 33.09 |   |   |
| Outstanding, end of year                                                                            | ** ** | **6,051**                             | ** ** |                                        | **$**      | **47.23**  |       |   | 7,172 |   |   | $ | 45.24 |   |   | 7,365 |   |   | $ | 31.62 |   |   |
| Exercisable, end of year                                                                            | ** ** | **4,401**                             | ** ** |                                        | **$**      | **46.94**  |       |   | 4,022 |   |   | $ | 45.31 |   |   | 3,844 |   |   | $ | 29.99 |   |   |
| Weighted-average fair value per share of options granted with  exercise prices at fair market value | ** ** | ** **                            | ** ** |                                        | **$**      | **—** |       |   |   |   |   | $ | 7.13 |   |   |   |   |   | $ | 7.22 |   |   |

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The following table summarizes additional information about stockoptions during 2006, 2005 and 2004:
| ** **                           | ** ** | **2006**                 | ** ** | **2005** | ** ** | **2004** | ** ** |
|--------------------------------------|------------|--------------------------|------------|----------|------------|----------|------------|
| ** **                           | ** ** | ***(In millions)*** | ** ** |
| Stock Option Expense Recognized      | ** ** | **$**                    | **6.7**    |     | $          | 14.4     |       | $ | 1.0 |   |
| Stock Options Exercised:             | ** ** | ** **               |       |     |       |     |       |
| Cash Received for Exercise Price     | ** ** | **35.5**                 |       | 35.3     |       | 23.7     |       |
| Intrinsic Value Realized by Employee | ** ** | **27.6**                 |       | 109.8    |       | 10.5     |       |
| Realized Tax Benefit                 | ** ** | **10.9**                 |       | 43.4     |       | 4.2      |       |
| Fair Value of Shares that Vested     | ** ** | **82.6**                 |       | 232.0    |       | 59.0     |       |
|                                      |            |                          |            |          |            |          |            |  |  |  |

 

As of December 31, 2006, wehad $2.8 million of unrecognized compensation cost related to the unvestedportion of outstanding stock option awards, of which $2.5 million is expectedto be recognized during 2007.

The following table summarizes additionalinformation about stock options outstanding at December 31, 2006 (stockoptions in thousands):
| ** **                          | ** **   | **Outstanding**    | ** **   | **Exercisable**                 | ** **   | **Weighted-  Average** | ** **   |
|-------------------------------------|--------------|--------------------|--------------|---------------------------------|--------------|------------------------|--------------|
| **Range of  Exercise  Prices** | ** **   | **Stock  Options** | ** **   | **Aggregate  Intrinsic  Value** | ** **   | **Stock  Options**     | ** **   | **Aggregate  Intrinsic  Value** | ** ** | **Remaining  Contractual  Life** | ** ** |
| *** ***                        | *** *** | *** ***       | *** *** | ***(In millions)***        | *** *** | *** ***           | *** *** | ***(In millions)*** | *** *** | ***(In years)*** | *** *** |
| $20.00 - $30.00           |         |               | 621          |                            |         |                   | $            | 24.8 |   |   |   | 621 |   |   |   | $ | 24.8 |   |   |   | 6.2 |   |   |
| $30.00 - $40.00           |         |               | 1,655        |                            |         |                   | 52.6         |   |   |   | 1,209 |   |   |   | 39.6 |   |   |   | 6.5 |   |   |
| $40.00 - $50.00           |         |               | 57           |                            |         |                   | 1.6          |   |   |   | 35 |   |   |   | 1.0 |   |   |   | 7.4 |   |   |
| $50.00 - $60.00           |         |               | 3,718        |                            |         |                   | 50.4         |   |   |   | 2,536 |   |   |   | 30.0 |   |   |   | 6.7 |   |   |
|                                |         |               | 6,051        |                            |         |                   | $            | 129.4 |   |   |   | 4,401 |   |   |   | $ | 95.4 |   |   |   |   |   |   |

 

**Restricted Stock Awards**

In addition tostock options, we issue common stock based on meeting certain service goals.This stock vests to participants at various times ranging from one to fiveyears if the service goals are met. In accordance with SFAS No. 123R, weaccount for our service-based awards as equity awards, whereby werecognize the value of the market price of the underlying stock on the date ofgrant to compensation expense over the service period either ratably or intranches (depending if the award has cliff or graded vesting).

We recorded compensation expense related toour restricted stock awards of $24.5 million in 2006, $28.2 million in2005, and $17.0 million in 2004. Summarized share information for ourrestricted stock awards is as follows:
| ** **                                                                 | ** ** | **2006**                              | ** ** | **2005** | ** ** | **2004** | ** ** |
|----------------------------------------------------------------------------|------------|---------------------------------------|------------|----------|------------|----------|------------|
| ** **                                                                 | ** ** | ***(Shares in thousands)*** | ** ** |
| Outstanding, beginning of year                                             | ** ** | **1,272**                             |       | 1,223    |       | 752      |       |
| Granted                                                                    | ** ** | **511**                               |       | 485      |       | 1,002    |       |
| Released to  participants                                                  | ** ** | **(502**                              | **)**      | (359     | )          | (467     | )          |
| Canceled                                                                   | ** ** | **(74**                               | **)**      | (77      | )          | (64      | )          |
| Outstanding, end of year                                                   | ** ** | **1,207**                             |       | 1,272    |       | 1,223    |       |
| Weighted-average fair value of restricted stock granted (per  share)       | ** ** | **$**                                 | **58.68**  |     | $          | 51.23    |       | $ | 38.83 |   |
| Total fair value of shares for which restriction has lapsed (in  millions) | ** ** | **$**                                 | **27.6**   |     | $          | 19.0     |       | $ | 18.8 |   |

 

As of December 31, 2006, we had $16.2 million of unrecognizedcompensation cost related to the unvested portion of outstanding restrictedstock awards expected to be recognized within a two-year period. At December 31,2006, we have recorded in “Common shareholders’ equity” approximately$31.7 million and approximately $21 million at December 31, 2005 forthe unvested portion of service-based restricted stock granted from 2001until 2006 to officers and other employees that is contingently redeemable incash upon a change in control.

**Performance-Based Units**

In accordance with SFAS No. 123R, we recognize compensationexpense ratably for our performance-based awards, which are classified asliability awards, for which the fair value of the award is remeasured at eachreporting period. Each unit is equivalent to $1 in value and cliff vests at theend of a three-year service and performance period. The level of payout isbased on the achievement of certain performance goals at the end of thethree-year period and will be settled in cash. We recorded compensation expenseof $24.0 million in 2006, $7.0 million in 2005, and $2.9 million in2004 for these awards. No awards were settled during the year, and as of December 31,2006 we had $9.9 million of unrecognized compensation cost related to theunvested portion of outstanding performance-based unit awards expected tobe recognized within a 14-month period.

**Equity-Based Grants**

We recordedcompensation expense of $0.6 million in 2006, $0.5 million in 2005, and$0.5 million in 2004 related to equity-based grants to members ofthe Board of Directors.

 

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**15**Mergerand Acquisitions

**Termination of Merger Agreement with FPLGroup, Inc.**

On October 24, 2006,Constellation Energy and FPL Group agreed to terminate the Agreement and Planof Merger the parties had entered into on December 18, 2005. In connection with the termination of themerger agreement, Constellation Energy acquired certain development rights fromFPL Group relating to a wind power project in Western Maryland.

Pursuant to theterms of the termination agreement, if Constellation Energy announces its entryinto certain types of transactions on or prior to September 30, 2007,including a merger or stock sale resulting in a third party owning 35% or moreof the voting securities of Constellation Energy, it will be required to payFPL Group a fee. The fee is $425 million if a transaction is announced on orprior to June 30, 2007 and $210 million if a transaction is announcedbetween July 1, 2007 and September 30, 2007.

We incurred merger costs during the year ended December 31, 2006totaling $18.3 million pre-tax. Our total pre-tax merger-related costswere $35.3 million.

**Acquisitions of Working Interests in GasProducing Fields**

In the firstquarter of 2006, we acquired working interests in gas and oil producingproperties for approximately $100 million in cash. We purchased leases,producing wells, and related equipment. We have included the results ofoperations in our merchant energy business segment since the date ofacquisition.

In June 2005, we acquired working interests in gas producingfields in Texas and Alabama for approximately $211 million in cash and theassumption of below-market natural gas swaps and other liabilitiestotaling approximately $18 million. The Texas asset acquisition was forapproximately a 70% working interest and the Alabama asset acquisition was fora 100% working interest. We have included the results of operations for theseworking interests in our merchant energy business segment since the date ofacquisition.

**Acquisition of Cogenex**

In April 2005,we acquired Cogenex Corporation from Alliant Energy Corporation. We includeCogenex with our other nonregulated businesses and have included their resultsin our consolidated financial statements since the date of acquisition. Cogenexis a North American energy services firm providing consulting and technologysolutions to industrial, institutional, and governmental customers. We acquired100% ownership of Cogenex for $34.9 million. We acquired cash of$14.4 million as part of the purchase.

Our final purchase price allocation for thenet assets acquired is as follows:
| ***At April 1, 2005***  | ** ** | ** **               | ** ** |
|----------------------------------------|------------|--------------------------|------------|
| ** **                             | ** ** | ***(In millions)*** | ** ** |
| Cash                                   |       |                     | $          | 14.4 |   |   |
| Other Current Assets                   |       |                     | 12.4       |   |   |
| Total Current Assets                   |       |                     | 26.8       |   |   |
| Net Property, Plant and Equipment      |       |                     | —     |   |   |
| Other Assets                           |       |                     | 34.9       |   |   |
| Total Assets Acquired                  |       |                     | 61.7       |   |   |
| Current Liabilities                    |       |                     | (8.0       | ) |   |
| Deferred Credits and Other Liabilities |       |                     | (18.8      | ) |   |
| Net Assets Acquired                    |       |                     | $          | 34.9 |   |   |

 

We believe thatthe pro-forma impact of the Cogenex acquisition would not have been material toour results of operations in 2005.

----

**16**RelatedParty Transactions—BGE

**IncomeStatement**

BGE is obligated to provide market-based standard offer service to allof its electric customers for varying periods. Bidding to supplyBGE’s market-based standard offer service to electric customers will occur fromtime to time through a competitive bidding process approved by the MarylandPSC.

Our wholesalemarketing, risk management, and trading operation will supply a substantialportion of BGE’s market-based standard offer service obligation to residentialelectric customers through May 31, 2007, as well as a portion of BGE’smarket-based standard offer service obligations for all electric customers fromJune 1, 2007 through May 31, 2009.

The cost of BGE’s purchased energy fromnonregulated subsidiaries of Constellation Energy to meet its standard offerservice obligation was as follows:
| ***Year Ended December 31,*** | ** ** | **2006**                 | ** **  | **2005** | ** ** | **2004** | ** ** |
|----------------------------------------------|------------|--------------------------|-------------|----------|------------|----------|------------|
| ** **                                   | ** ** | ***(In millions)*** | ** **  |
| Electricity purchased for resale expenses    | ** ** | **$**                    | **1,062.0** |     | $          | 805.9    |       | $ | 948.9 |   |
|                                              |            |                          |             |          |            |          |            |  |  |  |

 

In addition,Constellation Energy charges BGE for the costs of certain corporate functions.Certain costs are directly assigned to BGE. We allocate other corporatefunction costs based on a total percentage of expected use by BGE. We believethis method of allocation is reasonable and approximates the cost BGE wouldhave incurred as an unaffiliated entity.

The following table presents the costsConstellation Energy charged to BGE in each period.
| ***Year ended December 31,*** | ** ** | **2006**                 | ** ** | **2005** | ** ** | **2004** | ** ** |
|----------------------------------------------|------------|--------------------------|------------|----------|------------|----------|------------|
| ** **                                   | ** ** | ***(In millions)*** | ** ** |
| Charges to BGE                               | ** ** | **$**                    | **148.8**  |     | $          | 130.3    |       | $ | 99.8 |   |
|                                              |            |                          |            |          |            |          |            |  |  |  |

 

**Balance Sheet**

BGEparticipates in a cash pool under a Master Demand Note agreement withConstellation Energy. Under this arrangement, participating subsidiaries mayinvest in or borrow from the pool at market interest rates. ConstellationEnergy administers the pool and invests excess cash in short-term investmentsor issues commercial paper to manage consolidated cash requirements. Under thisarrangement, BGE had invested $60.6 million at 

117

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December 31,2006 and borrowed $3.2 million at December 31, 2005.

BGE’sConsolidated Balance Sheets include intercompany amounts related to corporatefunctions performed at the Constellation Energy holding company, BGE’s purchasesto meet its standard offer service obligation, BGE’s charges to ConstellationEnergy and its nonregulated affiliates for certain services it provides them,and the participation of BGE’s employees in the Constellation Energy definedbenefit plans.

We believe ourallocation methods are reasonable and approximate the costs that would becharged to unaffiliated entities.

----

**17**Quarterly Financial Data (Unaudited)

Our quarterly financial information has notbeen audited but, in management’s opinion, includes all adjustments necessaryfor a fair statement. Our business is seasonal in nature with the peak salesperiods generally occurring during the summer and winter months. Accordingly,comparisons among quarters of a year may not represent overall trends andchanges in operations.
| 2006 Quarterly Data—Constellation Energy | ** ** | **2006 Quarterly Data—BGE**                             | ** ** |
|--------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                   | ** ** | **Revenues**                                                           | ** ** | **Income  from  Operations** | ** ** | **Income  from  Continuing  Operations** | ** ** | **Earnings  Applicable  to  Common  Stock** | ** ** | **Earnings  Per Share  from  Continuing  Operations-  Diluted** | ** ** | **Earnings Per  Share of  Common  Stock-  Diluted** | ** ** | ** ** | ** ** | **Revenues** | ** ** | **Income  from  Operations** | ** ** | **Earnings  Applicable  to Common  Stock** | ** ** |
| ** **                                                   | ** ** | ***(In millions, except per share amounts)*** | ** ** | ** ** | ** ** | ***(In millions)*** | ** ** |
|                                                              |            |                                                                        |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Quarter Ended  March 31* | ** ** | **$**       | **4,859.2**  | ** ** | ** ** | **$**  | **204.0**   |       | ** ** | ** ** | **$**      | **101.6**  |      | ** ** | ** ** | **$**      | **113.9** |   | ** ** | ** ** | **$**    | **0.56** |   | ** **        | ** ** | **$**     | **0.63**   |       |     | Quarter Ended  March 31 | ** ** | **$**      | **924.2**   | ** ** | ** ** | **$** | **141.1** |   | ** ** | ** ** | **$** | **68.4**  |   |   |
|-------------------------------|------------|-------------|--------------|------------|------------|--------|-------------|------------|------------|------------|------------|------------|-----------|------------|------------|------------|-----------|--------|------------|------------|----------|----------|--------|-------------------|------------|-----------|------------|------------|----------|------------------------------|------------|------------|-------------|------------|------------|-------|-----------|--------|------------|------------|-------|-----------|--------|--------|
| June 30*                 | ** ** | **4,378.8** | ** **   | ** ** | **178.3**  |   | ** **  | ** ** | **74.0**   |       | ** ** | ** ** | **93.1**  |       | ** ** | ** ** | **0.41**  |   | ** ** | ** ** | **0.52** |     |   | June 30      | ** ** | **642.3** | ** ** | ** ** | **58.5** |                         | ** ** | ** ** | **18.4**    |       |       |
| September 30*            | ** ** | **5,393.4** | ** **   | ** ** | **530.9**  |   | ** **  | ** ** | **306.4**  |       | ** ** | ** ** | **324.4** |       | ** ** | ** ** | **1.69**  |   | ** ** | ** ** | **1.79** |     |   | September 30 | ** ** | **764.5** | ** ** | ** ** | **83.0** |                         | ** ** | ** ** | **35.6**    |       |       |
| December 31              | ** ** | **4,653.5** | ** **   | ** ** | **420.3**  |   | ** **  | ** ** | **266.6**  |       | ** ** | ** ** | **405.0** |       | ** ** | ** ** | **1.46**  |   | ** ** | ** ** | **2.22** |     |   | December 31  | ** ** | **684.4** | ** ** | ** ** | **86.5** |                         | ** ** | ** ** | **34.7**    |       |       |
| Year Ended  December 31  | ** ** | **$**       | **19,284.9** | ** ** | ** ** | **$**  | **1,333.5** |       | ** ** | ** ** | **$**      | **748.6**  |      | ** ** | ** ** | **$**      | **936.4** |   | ** ** | ** ** | **$**    | **4.12** |   | ** **        | ** ** | **$**     | **5.16**   |       |     | Year Ended  December 31 | ** ** | **$**      | **3,015.4** | ** ** | ** ** | **$** | **369.1** |   | ** ** | ** ** | **$** | **157.1** |   |   |

*The sum of the quarterly earnings per shareamounts may not equal the total for the year due to the effects of rounding anddilution as a result of issuing common shares during the year.*

First quarter results include:

 ̈  an$11.4 million gain after-tax for the discontinued operations of our High Desertfacility,

 ̈  a$0.9 million gain after-tax for the discontinued operations of our othernonregulated international operations,

 ̈  merger-relatedcosts totaling $1.5 million after-tax, of which BGE recorded $0.5 millionafter-tax, and

 ̈  workforcereduction costs totaling $1.3 million after-tax.

Second quarter results include:

 ̈  a$19.1 million gain after-tax for the discontinued operations of our High Desertfacility, and

 ̈  merger-relatedcosts totaling $6.0 million after-tax, of which BGE recorded $1.6 millionafter-tax.

Third quarter results include:

 ̈  an$18.0 million gain after-tax for the discontinued operations of our High Desertfacility,

 ̈  workforcereduction costs totaling $13.1 million after-tax, and

 ̈  merger-relatedcosts totaling $2.5 million after-tax, of which BGE recorded $0.7 millionafter-tax.

Fourth quarter results include:

 ̈  a$47.1 million gain after-tax on sale of gas-fired plants,

 ̈  a$17.9 million gain after-tax on the initial public offering of CEP,

 ̈  a$138.4 million gain after-tax for the discontinued operations of our HighDesert facility,

 ̈  workforcereduction costs totaling $2.6 million after-tax, and

 ̈  taxbenefits associated with merger-related costs totaling $(4.3) million after-tax,of which BGE recorded $(1.6) million after-tax.

We discuss these items in *Note 2*.

** Due to the reclassification of our HighDesert facility to discontinued operations, we have reclassified certainamounts previously reported in our first, second, and third quarterForm 10-Qs. The following is a reconciliation of amounts previouslyreported to amounts currently presented for those items.*

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| ***For the quarter ended*** | ** ** | **March 31, 2006**                                           | ** ** | **June 30, 2006**  | ** ** | **September 30, 2006** | ** ** |
|--------------------------------------------|------------|------------------------------------------------------------------------|------------|------------------------------|------------|----------------------------------|------------|
| ** **                                 | ** ** | **As Reported**                                                   | ** ** | **Discontinued  Operations** | ** ** | **Reclassified**                 | ** ** | **As Reported** | ** ** | **Discontinued  Operations** | ** ** | **Reclassified** | ** ** | **As Reported** | ** ** | **Discontinued  Operations** | ** ** | **Reclassified** | ** ** |
| ** **                                 | ** ** | ***(In millions, except per share amounts)*** | ** ** |
|                                            |            |                                                                        |            |                              |            |                                  |            |  |  |  |  |  |  |  |  |  |  |  |  |
| Revenues                                                    | ** ** |   | **$**     | **4,897.5** | ** ** |   |      | **$** | **(38.3** | **)**  |      |       | **$**  | **4,859.2** | ** ** |       |   | **$**  | **4,421.9** | ** ** |   |   | **$**     | **(43.1**  | **)**  |   |      | **$**      | **4,378.8** | ** ** |      |   | **$**  | **5,433.7** | ** ** |       |   | **$** | **(40.3** | **)** |   |   | **$** | **5,393.4** | ** ** |   |
|-------------------------------------------------------------|------------|--------|-----------|-------------|------------|--------|-----------|-------|-----------|--------|-----------|------------|--------|-------------|------------|------------|--------|--------|-------------|------------|--------|--------|-----------|------------|--------|--------|-----------|------------|-------------|------------|-----------|--------|--------|-------------|------------|------------|--------|-------|-----------|-------|--------|--------|-------|-------------|------------|--------|
| Income from Operations                                      | ** ** |   | **222.5** | ** **  |       |   | **(18.5** | **)** |      |   | **204.0** | ** ** |   |        | **208.7**  | ** ** |   |   | **(30.4**   | **)**      |   |   | **178.3** | ** ** |   |   | **559.9** | ** ** |        |       | **(29.0** | **)**  |   |        | **530.9**  | ** ** |   |
| Income from Continuing Operations                           | ** ** |   | **113.0** | ** **  |       |   | **(11.4** | **)** |      |   | **101.6** | ** ** |   |        | **93.1**   | ** ** |   |   | **(19.1**   | **)**      |   |   | **74.0**  | ** ** |   |   | **324.4** | ** ** |        |       | **(18.0** | **)**  |   |        | **306.4**  | ** ** |   |
| Earnings Per Share from  Continuing Operations—Diluted | ** ** |   | **0.63**  | ** **  |       |   | **(0.07** | **)** |      |   | **0.56**  | ** ** |   |        | **0.52**   | ** ** |   |   | **(0.11**   | **)**      |   |   | **0.41**  | ** ** |   |   | **1.79**  | ** ** |        |       | **(0.10** | **)**  |   |        | **1.69**   | ** ** |   |

 
| **2005 Quarterly Data—Constellation Energy** | ** ** | **2005 Quarterly Data—BGE**                             | ** ** |
|------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **Revenues**                                                           | ** ** | **Income  from  Operations** | ** ** | **Income  from  Continuing  Operations  and Before  Cumulative  Effects of  Changes in  Accounting  Principles** | ** ** | **Earnings  Applicable  to  Common  Stock** | ** ** | **Earnings  Per Share  from  Continuing  Operations  and Before  Cumulative  Effects of  Changes in  Accounting  Principles-  Diluted** | ** ** | **Earnings Per  Share of  Common  Stock-  Diluted** | ** ** | ** ** | ** ** | **Revenues** | ** ** | **Income  from  Operations** | ** ** | **Earnings  Applicable  to Common  Stock** | ** ** |
| ** **                                                       | ** ** | ***(In millions, except per share amounts)*** | ** ** | ** ** | ** ** | ***(In millions)*** | ** ** |
|                                                                  |            |                                                                        |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Quarter Ended  March 31* |   | $       | 3,532.6  |   |   | $      | 193.8  |   |   |   | $      | 100.8  |   |   |   | $      | 120.7 |   |   |   | $    | 0.57   |   |              |   | $     | 0.68   |   |   | Quarter  Ended  March 31 |   | $      | 857.3   |   |   | $ | 143.7 |   |   |   | $ | 71.0  |   |   |
|-------------------------------|--------|---------|----------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|-------|--------|--------|--------|------|--------|--------|-------------------|--------|-------|--------|--------|--------|-------------------------------|--------|--------|---------|--------|--------|---|-------|--------|--------|--------|---|-------|--------|--------|
| June 30*                 |   | 3,438.0 |     |   | 183.0  |   |   |   | 101.1  |   |   |   | 121.7  |   |   |   | 0.57  |   |   |   | 0.68 |   |   | June 30      |   | 610.3 |   |   | 64.4   |                          |   |   | 23.6    |   |   |
| September 30*            |   | 4,879.9 |     |   | 287.4  |   |   |   | 165.5  |   |   |   | 185.5  |   |   |   | 0.92  |   |   |   | 1.03 |   |   | September 30 |   | 742.7 |   |   | 94.9   |                          |   |   | 42.4    |   |   |
| December 31              |   | 5,117.8 |     |   | 280.3  |   |   |   | 168.5  |   |   |   | 195.2  |   |   |   | 0.94  |   |   |   | 1.09 |   |   | December 31  |   | 799.0 |   |   | 93.5   |                          |   |   | 38.8    |   |   |
| Year Ended  December 31  |   | $       | 16,968.3 |   |   | $      | 944.5  |   |   |   | $      | 535.9  |   |   |   | $      | 623.1 |   |   |   | $    | 2.98   |   |              |   | $     | 3.47   |   |   | Year Ended December 31   |   | $      | 3,009.3 |   |   | $ | 396.5 |   |   |   | $ | 175.8 |   |   |

*The sum of the quarterly earnings per shareamounts may not equal the total for the year due to the effects of rounding anddilution as a result of issuing common shares during the year.*

First quarter results include:

 ̈  a$17.8 million gain after-tax for the discontinued operations of our High Desertfacility,

 ̈  a$1.7 million gain after-tax for the discontinued operations related to ourother nonregulated international investments, and

 ̈  a$0.4 million gain after-tax for the discontinued operations related to ourOleander facility.

Second quarter results include:

 ̈  a$16.7 million gain after-tax for the discontinued operations of our High Desertfacility,

 ̈  a$2.6 million gain after-tax for the discontinued operations related to ourOleander facility, and

 ̈  a$1.3 million gain after-tax income for discontinued operations related toour other nonregulated international investments.

Third quarter results include:

 ̈  an$18.6 million gain after-tax for the discontinued operations of our High Desertfacility,

 ̈  workforcereduction costs totaling $2.3 million after-tax, and

 ̈  a$1.4 million gain after-tax for discontinued operations related to ourother nonregulated international investments.

Fourth quarter results include:

 ̈  a$17.7 million gain after-tax for the discontinued operations of our High Desertfacility,

 ̈  a$16.2 million gain after-tax for discontinued operations related to ourother nonregulated international investments,

 ̈  merger-relatedcosts totaling $15.6 million after-tax, of which BGE recorded $5.0 millionafter-tax,

 ̈  a$7.4 million after-tax loss for the cumulative effect of adopting FIN 47,

 ̈  workforcereduction costs totaling $0.3 million after-tax, and

 ̈  a$0.2 million after-tax gain for the cumulative effect of adopting SFAS No. 123R.

We discuss these items in *Note 2*.

** Due to the reclassification of our HighDesert facility to discontinued operations, we have reclassified certainamounts previously reported in our first, second, and third quarter Form 10-Qs. The following is areconciliation of amounts previously reported to amounts currently presentedfor those items.*

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| ***For the quarter ended***                                                                                     | ** ** | **March 31, 2005**                                           | ** ** | **June 30, 2005**  | ** ** | **September 30, 2005** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                                     | ** ** | **As  Reported**                                                       | ** ** | **Discontinued  Operations** | ** ** | **Reclassified**                 | ** ** | **As Reported** | ** ** | **Discontinued  Operations** | ** ** | **Reclassified** | ** ** | **As Reported** | ** ** | **Discontinued  Operations** | ** ** | **Reclassified** | ** ** |
| ** **                                                                                                                     | ** ** | ***(In millions, except per share amounts)*** | ** ** |
| Revenues                                                                                                                       |       | $                                                                      | 3,572.0    |                         |       | $                                | (39.4      | ) |   |   | $ | 3,532.6 |   |   |   | $ | 3,478.5 |   |   |   | $ | (40.5 | ) |   |   | $ | 3,438.0 |   |   |   | $ | 4,922.4 |   |   |   | $ | (42.5 | ) |   |   | $ | 4,879.9 |   |   |
| Income from Operations                                                                                                         |       | 221.9                                                                  |       |                         | (28.1      | )                                |       |   | 193.8 |   |   |   | 209.8 |   |   |   | (26.8 | ) |   |   | 183.0 |   |   |   | 317.0 |   |   |   | (29.6 | ) |   |   | 287.4 |   |   |
| Income from Continuing  Operations and Before Cumulative Effects of Changes in Accounting Principles                           |       | 118.6                                                                  |       |                         | (17.8      | )                                |       |   | 100.8 |   |   |   | 117.8 |   |   |   | (16.7 | ) |   |   | 101.1 |   |   |   | 184.1 |   |   |   | (18.6 | ) |   |   | 165.5 |   |   |
| Earnings Per Share from  Continuing Operations and Before Cumulative Effects of Changes in Accounting  Principles—Diluted |       | 0.67                                                                   |       |                         | (0.10      | )                                |       |   | 0.57 |   |   |   | 0.66 |   |   |   | (0.09 | ) |   |   | 0.57 |   |   |   | 1.02 |   |   |   | (0.10 | ) |   |   | 0.92 |   |   |
|                                                                                                                                |            |                                                                        |            |                              |            |                                  |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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** **

**Item 9. Changes inand Disagreements with Accountants on Accounting and Financial Disclosure**

None.

 

**Item 9A. Controls andProcedures**

***Evaluation ofDisclosure Controls and Procedures***

The principal executive officers and principal financial officer ofboth Constellation Energy and BGE have evaluated the effectiveness of thedisclosure controls and procedures (as such term is defined in Rules 13a-15(e) and15d-15(e) under the Securities Exchange Act of 1934, as amended (the“Exchange Act”)) as of December 31, 2006 (the “Evaluation Date”). Based onsuch evaluation, such officers have concluded that, as of the Evaluation Date,Constellation Energy’s and BGE’s disclosure controls and procedures areeffective.

***InternalControl Over Financial Reporting***

Constellation Energy maintains a system of internal control overfinancial reporting as defined in Exchange Act Rule 13a-15(f).Constellation Energy’s Management Report on Internal Control Over FinancialReporting is included in *Item 8. FinancialStatements and Supplementary Data* included in this report. As BGE isnot an accelerated filer as defined in Exchange Act Rule 12b-2, itis not required to provide a report of management on the effectiveness of itsinternal control over financial reporting as of December 31, 2006, butwill be required to do so as of December 31, 2007.

***Changes in Internal Control***

During the quarter ended December 31, 2006, there has been nochange in either Constellation Energy’s or BGE’s internal control overfinancial reporting (as such term is defined in Rules 13a-15(f) and15d-15(f) under the Exchange Act) that has materially affected, oris reasonably likely to materially affect, either Constellation Energy’s or BGE’sinternal control over financial reporting.

** **

**Item 9B. OtherInformation**

None.

 

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**PART III**

BGE meets the conditions set forth in General Instruction I(1)(a) and(b) of Form 10-K for a reduced disclosure format. Accordingly,all items in this section related to BGE are not presented.

**Item 10. Directors and Executive Officers of the Registrant**

The informationrequired by this item with respect to directors will be set forth under *Election of Directors* in the ProxyStatement and incorporated herein by reference.

The information required by this item with respect to executiveofficers of Constellation Energy Group, pursuant to instruction 3 ofparagraph (b) of Item 401 of Regulation S-K, is set forthfollowing Item 4 of Part I of this Form 10-K under *Executive Officers of the Registrant*.

**Item 11. Executive Compensation**

The information required by this item will be set forth under *Executive and Director Compensation* and *Report of Compensation Committee*in theProxy Statement and incorporated herein by reference.

 

**Item 12. Security Ownership of Certain BeneficialOwners and Management and Related Shareholder Matters**

The additional information required by this item will be set forthunder *Stock Ownership* in theProxy Statement and incorporated herein by reference.

**Equity Compensation Plan Information**

The following table reflects our equitycompensation plan information as of December 31, 2006:
| ** **                                                      | ** **   | **(a)**                                                                                                                                           | ** **   | **(b)**                                                                                                      | ** **   | **(c)**                                                                                                                                                                                                            | ** ** |
|-----------------------------------------------------------------|--------------|---------------------------------------------------------------------------------------------------------------------------------------------------|--------------|--------------------------------------------------------------------------------------------------------------|--------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| ***Plan Category***                                        | ** **   | **Number of securities  to be issued upon  exercise of  outstanding options,  warrants, and rights** | ** **   | **Weighted-average  exercise price of  outstanding options,  warrants, and rights** | ** **   | **Number of securities remaining  available for future issuance  under equity compensation  plans (excluding securities  reflected in item (a))** | ** ** |
| *** ***                                                    | *** *** | ***(In thousands)***                                                                                                                         | *** *** | *** ***                                                                                                 | *** *** | ***(In thousands)***                                                                                                                                                                                          | ** ** |
| Equity compensation plans approved by security holders          |         |                                                                                                                                              | 4,414        |                                                                                                         |         |                                                                                                                                                                                                               | $          | 49.72 |   |   |   | 2,847 |   |   |
| Equity compensation plans not approved by security holders |         |                                                                                                                                              | 1,637        |                                                                                                         |         |                                                                                                                                                                                                               | $          | 40.53 |   |   |   | 892 |   |   |
| Total                                                           |         |                                                                                                                                              | 6,051        |                                                                                                         |         |                                                                                                                                                                                                               | $          | 47.23 |   |   |   | 3,739 |   |   |

 

The plans that do not require shareholder approval are theConstellation Energy Group, Inc. 2002 Senior Management Long-Term IncentivePlan (Designated as Exhibit No. 10(p)) and the Constellation EnergyGroup, Inc. Management Long-Term Incentive Plan (Designated as Exhibit No. 10(q)).A brief description of the material features of each of these plans is setforth below.

***2002 Senior Management Long-Term IncentivePlan***

The 2002 Senior Management Long-Term Incentive Plan was effective May 24,2002. Grants under the plan may be made to employees who are officers ofConstellation Energy or hold senior management level or key employee positionswith Constellation Energy or its subsidiaries. Under the plan, the Board ofConstellation Energy has authorized the issuance of up to 4,000,000 shares ofConstellation Energy common stock in connection with the grant of stock options,performance and service-based restricted stock and restricted stockunits, performance units, stock appreciation rights, dividend equivalents andother equity awards. Any shares covered by an award that is forfeited orcanceled, expires or is settled in cash, including the settlement of taxwithholding obligations using shares, will become available for issuance underthe plan. Shares delivered under the plan may be authorized and unissued sharesor shares purchased on the open market in accordance with the applicablesecurities laws. Restricted stock, restricted stock unit, and performance unitaward payouts will be accelerated and stock options and stock appreciationrights gains will be paid in cash in the event of a change in control, asdefined in the plan. The plan is administered by Constellation Energy’s ChiefExecutive Officer.

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***Management Long-Term Incentive Plan***

The Management Long-Term Incentive Plan was effective February 1,1998. Grants under the plan may be made to employees of Constellation Energywho hold a management level position and other employees of ConstellationEnergy and its subsidiaries as may be designated by Constellation Energy’sChief Executive Officer. Under the plan, the Board of Constellation Energy hasauthorized the issuance of up to 3,000,000 shares of Constellation Energycommon stock in connection with the grant of stock options, performance andservice-based restricted stock and restricted stock units, performanceunits, stock appreciation rights and dividend equivalents. The number of sharesavailable for issuance under the plan includes shares subject to awards thathave lapsed or terminated. Shares delivered under the plan may be authorizedand unissued shares or shares purchased on the open market in accordance withapplicable securities laws. Restricted stock, restricted stock unit, andperformance unit award payouts will be accelerated and stock options and stockappreciation rights will become fully exercisable in the event of a change incontrol, as defined by the plan. The plan is administered by ConstellationEnergy’s Chief Executive Officer.

**Item 13. Certain Relationships and Related Transactions**

The additional information required by this item will be set forthunder *Related Persons Transactions andDetermination of Independence* in the Proxy Statement andincorporated herein by reference.

**Item 14. Principal Accountant Fees and Services**

The information required by this item will be set forth under *Ratification of Appointment of PricewaterhouseCoopersLLP as Independent Registered Public Accounting Firm for 2007* in theProxy Statement and incorporated herein by reference.

**PART IV**

**Item 15. Exhibitsand Financial Statement Schedules**
|        |   | (a) The following  documents are filed as a part of this Report:                                                                                               |
|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 1.     |   | Financial Statements:                                                                                                                                               |
|   |   | Reports of Independent Registered Public Accounting Firm dated  February 26, 2007 of PricewaterhouseCoopers LLP                                                |
|   |   | Consolidated Statements of  Income—Constellation Energy Group for three years ended December 31,  2006                                                    |
|   |   | Consolidated Balance  Sheets—Constellation Energy Group at December 31, 2006 and  December 31, 2005                                                  |
|   |   | Consolidated Statements of Cash Flows—Constellation Energy Group for  three years ended December 31, 2006                                            |
|   |   | Consolidated Statements of Common Shareholders’ Equity and  Comprehensive Income—Constellation Energy Group for three years ended  December 31, 2006 |
|   |   | Consolidated Statements of Capitalization—Constellation Energy Group  at December 31, 2006 and December 31, 2005                                     |
|   |   | Consolidated Statements of Income—Baltimore Gas and Electric Company  for three years ended December 31, 2006                                        |
|   |   | Consolidated Statements of Comprehensive Income—Baltimore Gas and  Electric Company for three years ended December 31, 2006                               |
|   |   | Consolidated Balance Sheets—Baltimore Gas and Electric Company at  December 31, 2006 and December 31, 2005                                      |
|   |   | Consolidated Statements of Cash Flows—Baltimore Gas and Electric  Company for three years ended December 31, 2006                                         |
|   |   | Notes to Consolidated  Financial Statements                                                                                                                         |
| 2.     |   | Financial Statement Schedules:                                                                                                                                      |
|   |   | Schedule II—Valuation and  Qualifying Accounts                                                                                                                 |
|   |   | Schedules other than Schedule  II are omitted as not applicable or not required.                                                                                    |
| 3.     |   | Exhibits Required by Item 601 of Regulation S-K.                                                                                                                    |

 

123

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| Exhibit  Number | ** ** | ** ** | ** ** | ** ** |
|-----------------|------------|------------|------------|------------|
| *2              |       |       | —     |       | Agreement and Plan of Share Exchange between Baltimore Gas and  Electric Company and Constellation Energy Group, Inc. dated as of  February 19, 1999. (Designated as Exhibit No. 2 to the  Registration Statement on Form S-4 dated March 3, 1999, File  No. 33-64799.) |
| *2              | (a)        |       | —     |       | Agreement and Plan of Reorganization and Corporate Separation  (Nuclear). (Designated as Exhibit No. 2(a) to the Current  Report on Form 8-K dated July 7, 2000, File Nos. 1-12869  and 1-1910.) |
| *2              | (b)        |       | —     |       | Agreement and Plan of Reorganization and Corporate Separation  (Fossil). (Designated as Exhibit No. 2(b) to the Current  Report on Form 8-K dated July 7, 2000, File Nos. 1-12869  and 1-1910.) |
| *2              | (c)        |       | —     |       | Purchase and Sale Agreement by and between Constellation  Power, Inc. and TPF Generation Holdings, LLC dated as of  October 10, 2006. (Designated as  Exhibit 2(a) to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.) |
| *2              | (d)        |       | —     |       | Termination and Release Agreement, dated October 24, 2006, by  and among Constellation Energy Group, Inc., FPL Group, Inc. and CF  Merger Corporation (Designated as Exhibit 2.1 to the Current Report on  Form 8-K dated October 25, 2006, File Nos. 1-12869 and  1-1910.) |
| *3              | (a)        |       | —     |       | Articles of Amendment and Restatement of the Charter of Constellation  Energy Group, Inc. as of April 30, 1999. (Designated as  Exhibit No. 99.2 to the Current Report on Form 8-K dated  April 30, 1999, File No. 1-1910.) |
| *3              | (b)        |       | —     |       | Articles Supplementary to the Charter of Constellation Energy  Group, Inc., as of July 19, 1999. (Designated as  Exhibit No. 3(a) to the Quarterly Report on Form 10-Q  for the quarter ended June 30, 1999, File Nos. 1-12869 and 1-1910.) |
| *3              | (c)        |       | —     |       | Certificate of Correction to the Charter of Constellation Energy  Group, Inc. as of September 13, 1999. (Designated as  Exhibit No. 3(c) to the Annual Report on Form 10-K  for the year ended December 31, 1999, File Nos. 1-12869  and 1-1910.) |
| *3              | (d)        |       | —     |       | Charter of BGE, restated as of August 16, 1996. (Designated as  Exhibit No. 3 to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 1996, File No. 1-1910.) |
| *3              | (e)        |       | —     |       | Articles Supplementary to the Charter of Constellation Energy  Group, Inc. as of November 20, 2001. (Designated as  Exhibit No. 3(e) to the Annual Report on Form 10-K  for the year ended December 31, 2001, File Nos. 1-12869  and 1-1910.) |
| *3              | (f)        |       | —     |       | Bylaws of Constellation Energy Group, Inc., as amended to October 20,  2006. (Designated as Exhibit 3(a) to the Quarterly Report on  Form 10-Q for the quarter ended September 30, 2006, File  Nos. 1-12869 and 1-1910.) |
| *3              | (g)        |       | —     |       | Bylaws of BGE, as amended to October 16, 1998. (Designated as  Exhibit No. 3 to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 1998, File No. 1-1910.) |
| *4              | (a)        |       | —     |       | Indenture between Constellation Energy Group, Inc. and the Bank  of New York, Trustee dated as of March 24, 1999. (Designated as  Exhibit No. 4(a) to the Registration Statement on Form S-3  dated March 29, 1999, File No. 333-75217.) |
| *4              | (b)        |       | —     |       | First Supplemental Indenture between Constellation Energy  Group, Inc. and the Bank of New York, Trustee dated as of  January 24, 2003. (Designated as Exhibit No. 4(b) to the  Registration Statement on Form S-3 dated January 24, 2003,  File No. 333-102723.) |
| *4              | (c)        |       | —     |       | Supplemental Indenture between BGE and Bankers Trust Company, as  Trustee, dated as of June 20, 1995, supplementing, amending and  restating Deed of Trust dated February 1, 1919. (Designated as  Exhibit No. 4 to the Quarterly Report on Form 10-Q for  the quarter ended June 30, 1995, File No. 1-1910); as  supplemented by Supplemental Indentures dated as of June 15, 1996  (Designated as Exhibit No. 4 to the Quarterly Report on  Form 10-Q for the quarter ended June 30, 1996,) and as of  June 26, 2000 (filed herewith). |

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| *4  | (d) |   | — |   | Indenture dated July 1, 1985, between BGE and The Bank of New  York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee.  (Designated as Exhibit 4(a) to the Registration Statement on  Form S-3, File No. 2-98443); as supplemented by Supplemental  Indentures dated as of October 1, 1987 (Designated as  Exhibit 4(a) to the Current Report on Form 8-K, dated  November 13, 1987, File No. 1-1910) and as of  January 26, 1993 (Designated as Exhibit 4(b) to the Current  Report on Form 8-K, dated January 29, 1993, File No. 1-1910.) |
|-----|-----|--------|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *4  | (e) |   | — |   | Form of Subordinated Indenture between the Company and The Bank  of New York, as Trustee in connection with the issuance of the Junior  Subordinated Debentures. (Designated as Exhibit 4(d) to the  Registration Statement on Form S-3 dated August 5, 2003, File  No. 333-107681.)                                                                                                                                                                                                                                                                                                                               |
| *4  | (f) |   | — |   | Form of Supplemental Indenture between the Company and The Bank  of New York, as Trustee in connection with the issuances of the Junior  Subordinated Debentures. (Designated as Exhibit 4(e) to the  Registration Statement on Form S-3 dated August 5, 2003, File  No. 333-107681.)                                                                                                                                                                                                                                                                                                                              |
| *4  | (g) |   | — |   | Form of Preferred Securities Guarantee (Designated as  Exhibit 4(f) to the Registration Statement on Form S-3  dated August 5, 2003, File No. 333-107681.)                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| *4  | (h) |   | — |   | Form of Junior Subordinated Debenture (Designated as  Exhibit 4(h) to the Registration Statement on Form S-3  dated August 5, 2003, File No. 333-107681.)                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| *4  | (i) |   | — |   | Form of Amended and Restated Declaration of Trust (including  Form of Preferred Security) (Designated as Exhibit 4(c) to the  Registration Statement on Form S-3 dated August 5, 2003, File  No. 333-107681.)                                                                                                                                                                                                                                                                                                                                                                                                 |
| *4  | (j) |   | — |   | Indenture dated as of July 24, 2006 between Constellation Energy  Group, Inc. and Deutsche Bank Trust Company Americas, as trustee.  (Designated as Exhibit 4(a) to the Registration Statement on  Form S-3 filed July 24, 2006, File No. 333-135991.)                                                                                                                                                                                                                                                                                                                                                        |
| *4  | (k) |   | — |   | Indenture dated as of July 24, 2006 between Baltimore Gas and  Electric Company and Deutsche Bank Trust Company Americas, as trustee.  (Designated as Exhibit 4(b) to the Registration Statement on  Form S-3 filed July 24, 2006, File No. 333-135991.)                                                                                                                                                                                                                                                                                                                                                           |
| *4  | (l) |   | — |   | First Supplemental Indenture between Baltimore Gas and Electric  Company and Deutsche Bank Trust Company Americas, as trustee, dated as of  October 13, 2006. (Designated as  Exhibit 4(a) to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                                          |
| *4  | (m) |   | — |   | Registration Rights Agreement dated October 13, 2006 among  Baltimore Gas and Electric Company and the parties named therein relating to  5.90% Notes due 2016. (Designated as  Exhibit 4(b) to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                                        |
| *4  | (n) |   | — |   | Registration Rights Agreement dated October 13, 2006 among  Baltimore Gas and Electric Company and the parties named therein relating to  6.35% Notes due 2036. (Designated as  Exhibit 4(c) to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                                        |
| *10 | (a) |   | — |   | Executive Annual Incentive Plan of Constellation Energy  Group, Inc., as amended and restated. (Designated as  Exhibit No. 10(a) to the Quarterly Report on Form 10-Q  for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                                                                                              |
| *10 | (b) |   | — |   | Constellation Energy Group, Inc. 1995 Long-Term Incentive  Plan, as amended and restated. (Designated as  Exhibit No. 10(b) to the Quarterly Report on Form 10-Q  for the quarter ended September 30, 2004, File Nos. 1-12869  and 1-1910.)                                                                                                                                                                                                                                                                                                                                                              |
| *10 | (c) |   | — |   | Constellation Energy Group, Inc. Nonqualified Deferred  Compensation Plan, as amended and restated. (Designated as  Exhibit No. 10(c) to the Annual Report on Form 10-K  for the year ended December 31, 2002, File Nos. 1-12869  and 1-1910.)                                                                                                                                                                                                                                                                                                                                                           |
| *10 | (d) |   | — |   | Constellation Energy Group, Inc. Deferred Compensation Plan for  Non-Employee Directors, as amended and restated. (Designated as  Exhibit 10(a) to the Quarterly Report on Form 10-Q for  the Quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                                                                                     |

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| *10 | (e) |   | — |   | Compensation agreements between Constellation Energy Group, Inc.  and E. Follin Smith (Attachment 1—Employment Agreement; Attachment  2—Severance Agreement (Attachment 2 superseded by amended and restated change  in control severance agreement filed as Exhibit 10(y) to the Annual  Report on Form 10-K for the year ended December 31,  2005.)(Designated as Exhibit 10(c) to the Quarterly Report on  Form 10-Q for the quarter ended June 30, 2004, File  Nos. 1-12869 and 1-1910.) |
|-----|-----|--------|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *10 | (f) |   | — |   | Amended and restated change in control severance agreement between  Constellation Energy Group, Inc. and Thomas V. Brooks. (Designated as  Exhibit 10(f) to the Annual Report on Form 10-K for the  year ended December 31, 2005.)                                                                                                                                                                                                                                                                                                   |
| *10 | (g) |   | — |   | Grantor Trust Agreement Dated as of February 27, 2004 between  Constellation Energy Group, Inc. and Citibank, N.A. (Designated as  Exhibit No. 10(d) to the Quarterly Report on Form 10-Q  for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                        |
| *10 | (h) |   | — |   | Amended and restated change in control severance agreement between  Constellation Energy Group, Inc. and Mayo A. Shattuck III. (Designated  as Exhibit 10.2 to the Current Report on Form 8-K dated  December 19, 2005, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                               |
| *10 | (i) |   | — |   | Grantor Trust Agreement dated as of February 27, 2004 between  Constellation Energy Group, Inc. and T. Rowe Price Trust Company.  (Designated as Exhibit No. 10(b) to the Quarterly Report on  Form 10-Q for the quarter ended June 30, 2004, File  Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                         |
| *10 | (j) |   | — |   | Constellation Energy Group, Inc. Benefits Restoration Plan, as  amended and restated. (Designated as Exhibit No. 10(m) to the  Annual Report on Form 10-K for the year ended December 31,  2001, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                            |
| *10 | (k) |   | — |   | Constellation Energy Group, Inc. Supplemental Pension Plan, as  amended and restated. (Designated as Exhibit No. 10(d) to the  Quarterly Report on Form 10-Q for the quarter ended March 31,  2004, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                         |
| *10 | (l) |   | — |   | Constellation Energy Group, Inc. Senior Executive Supplemental  Plan, as amended and restated. (Designated as  Exhibit No. 10(e) to the Quarterly Report on Form 10-Q  for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                |
| *10 | (m) |   | — |   | Constellation Energy Group, Inc. Supplemental Benefits Plan, as  amended and restated. (Designated as Exhibit No. 10(p) to the  Annual Report on Form 10-K for the year ended December 31,  2001, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                           |
| *10 | (n) |   | — |   | Constellation Energy Group, Inc. Executive Long-Term  Incentive Plan, as amended and restated. (Designated as  Exhibit 10(b) to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                     |
| 10  | (o) |   | — |   | Constellation Energy Group, Inc. 2002 Executive Annual Incentive  Plan, as amended and restated.                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| *10 | (p) |   | — |   | Constellation Energy Group, Inc. 2002 Senior Management Long-Term  Incentive Plan, as amended and restated. (Designated as  Exhibit 10(c) to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                        |
| *10 | (q) |   | — |   | Constellation Energy Group, Inc. Management Long-Term  Incentive Plan, as amended and restated. (Designated as  Exhibit 10(d) to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                    |
| *10 | (r) |   | — |   | Summary of Constellation Energy Group, Inc. Board of Directors  Non-Employee Director Compensation Program. (Designated as  Exhibit 10(x) to the Annual Report on Form 10-K for the  year ended December 31, 2004, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                               |
| *10 | (s) |   | — |   | Amended and restated change in control severance agreement between  Constellation Energy Group, Inc. and E. Follin Smith. (Designated as  Exhibit 10(f) to the Annual Report on Form 10-K for the  year ended December 31, 2005.)                                                                                                                                                                                                                                                                                                    |
| 10  | (t) |   | — |   | Constellation Energy Group, Inc. 2007 Long-Term Incentive Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 12  | (a) |   | — |   | Constellation Energy Group, Inc. and Subsidiaries Computation of  Ratio of Earnings to Fixed Charges.                                                                                                                                                                                                                                                                                                                                                                                                                                                    |

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| 12 | (b)    |   | — |   | Baltimore Gas and Electric Company and Subsidiaries Computation of  Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to  Combined Fixed Charges and Preferred and Preference Dividend Requirements.                    |
|----|--------|--------|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 21 |   |   | — |   | Subsidiaries of the Registrant.                                                                                                                                                                                                               |
| 23 |   |   | — |   | Consent of PricewaterhouseCoopers LLP, Independent Registered Public  Accounting Firm.                                                                                                                                                        |
| 31 | (a)    |   | — |   | Certification of Chairman of the Board, Chief Executive Officer and  President of Constellation Energy Group, Inc. pursuant to  Section 302 of the Sarbanes-Oxley Act of 2002.                                                      |
| 31 | (b)    |   | — |   | Certification of Executive Vice President, Chief Financial Officer  and Chief Administrative Officer of Constellation Energy Group, Inc.  pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                |
| 31 | (c)    |   | — |   | Certification of President and Chief Executive Officer of Baltimore  Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002.                                                                                |
| 31 | (d)    |   | — |   | Certification of Senior Vice President and Chief Financial Officer of  Baltimore Gas and Electric Company pursuant to Section 302 of the  Sarbanes-Oxley Act of 2002.                                                                    |
| 32 | (a)    |   | — |   | Certification of Chairman of the Board, Chief Executive Officer and  President of Constellation Energy Group, Inc. pursuant to 18 U.S.C.  Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley  Act of 2002. |
| 32 | (b)    |   | — |   | Certification of Executive Vice President and Chief Financial Officer  of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350,  as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of  2002.         |
| 32 | (c)    |   | — |   | Certification of President and Chief Executive Officer of Baltimore  Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                            |
| 32 | (d)    |   | — |   | Certification of Senior Vice President and Chief Financial Officer of  Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350,  as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                |

 

*                      Incorporatedby Reference.

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**CONSTELLATIONENERGY GROUP, INC. AND SUBSIDIARIES**AND BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES

**SCHEDULE II—VALUATION ANDQUALIFYING ACCOUNTS**
| **Column A**                                                            | ** ** | **Column B**                          | ** ** | **Column C**                         | ** ** | **Column D**                                    | ** ** | **Column E**                | ** ** |
|------------------------------------------------------------------------------|------------|--------------------------------------------|------------|-------------------------------------------|------------|------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                   | ** ** | ** **                                 | ** ** | **Additions**                             | ** ** | ** **                                           | ** ** | ** **                       | ** ** |
| **Description**                                                              | ** ** | **Balance  at  beginning  of period** | ** ** | **Charged  to costs  and  expenses** | ** ** | **Charged to  Other  Accounts—  Describe** | ** ** | **(Deductions)—  Describe** | ** ** | **Balance at  end of  period** | ** ** |
| ** **                                                                   | ** ** | ***(In millions)***                   | ** ** |
| Reserves  deducted in the Balance Sheet from the assets to which they apply: |       |                                       |       |                                      |       |                                                 |       |                             |       |   |   |   |   |   |   |   |   |   |   |   |   |
| **Constellation Energy**                                                     |       |                                       |       |                                      |       |                                                 |       |                             |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Accumulated  Provision for Uncollectibles                                    |       |                                       |       |                                      |       |                                                 |       |                             |       |   |   |   |   |   |   |   |   |   |   |   |   |
| 2006                                                                         |       |                                       | $          | 47.4                                      |       |                                                 |       | $                                | 29.7       |   |   |   | $ | — |   |   |   | $ | (28.2 | )(A) |   |   | $ | 48.9 |   |   |
| 2005                                                                         |       |                                       | 43.1       |                                      |       |                                                 | 30.9       |                             |       |   | — |   |   |   | (26.6 | )(A) |   |   | 47.4 |   |   |
| 2004                                                                         |       |                                       | 51.7       |                                      |       |                                                 | 22.2       |                             |       |   | — |   |   |   | (30.8 | )(A) |   |   | 43.1 |   |   |
| Valuation  Allowance                                                         |       |                                       |       |                                      |       |                                                 |       |                             |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Net  unrealized (gain) loss on available for sale securities                 |       |                                       |       |                                      |       |                                                 |       |                             |       |   |   |   |   |   |   |   |   |   |   |   |   |
| 2006                                                                         |       |                                       | 0.6        |                                      |       |                                                 | —     |                             |       |   | (19.1 | )(B) |   |   | — |   |   |   | (18.5 | ) |   |
| 2005                                                                         |       |                                       | 0.1        |                                      |       |                                                 | —     |                             |       |   | 0.5 | (B) |   |   | — |   |   |   | 0.6 |   |   |
| 2004                                                                         |       |                                       | —     |                                      |       |                                                 | —     |                             |       |   | 0.1 | (B) |   |   | — |   |   |   | 0.1 |   |   |
| Net  unrealized (gain) loss on nuclear decommissioning trust funds           |       |                                       |       |                                      |       |                                                 |       |                             |       |   |   |   |   |   |   |   |   |   |   |   |   |
| 2006                                                                         |       |                                       | (110.3     | )                                         |       |                                                 | —     |                             |       |   | (95.8 | )(B) |   |   | — |   |   |   | (206.1 | ) |   |
| 2005                                                                         |       |                                       | (73.3      | )                                         |       |                                                 | —     |                             |       |   | (37.0 | )(B) |   |   | — |   |   |   | (110.3 | ) |   |
| 2004                                                                         |       |                                       | (13.7      | )                                         |       |                                                 | —     |                             |       |   | (59.6 | )(B) |   |   | — |   |   |   | (73.3 | ) |   |
| **BGE**                                                                      |       |                                       |       |                                      |       |                                                 |       |                             |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Accumulated  Provision for Uncollectibles                                    |       |                                       |       |                                      |       |                                                 |       |                             |       |   |   |   |   |   |   |   |   |   |   |   |   |
| 2006                                                                         |       |                                       | 13.0       |                                      |       |                                                 | 18.1       |                             |       |   | — |   |   |   | (15.0 | )(A) |   |   | 16.1 |   |   |
| 2005                                                                         |       |                                       | 13.0       |                                      |       |                                                 | 14.1       |                             |       |   | — |   |   |   | (14.1 | )(A) |   |   | 13.0 |   |   |
| 2004                                                                         |       |                                       | 10.7       |                                      |       |                                                 | 16.3       |                             |       |   | — |   |   |   | (14.0 | )(A) |   |   | 13.0 |   |   |
|                                                                              |            |                                            |            |                                           |            |                                                      |            |                                  |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

(A)            Represents principally net amounts chargedoff as uncollectible.

(B)            Represents amounts recorded in or reclassified fromaccumulated other comprehensive income.

128

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**SIGNATURES**

Pursuant to the requirements of Section 13or 15(d) of the Securities Exchange Act of 1934, Constellation EnergyGroup, Inc., the Registrant, has duly caused this Report to be signed onits behalf by the undersigned, thereunto duly authorized.
|                               |   |       |         |   | CONSTELLATION ENERGY GROUP, INC. (REGISTRANT)                                           |
|-------------------------------|--------|------------|--------------|--------|-----------------------------------------------------------------------------------------|
| Date:  February 27, 2007 | By     |       | /s/          |   | MAYO A. SHATTUCK III                                                                    |
|                          |   | ** ** | *** *** |   | **Mayo A. Shattuck III*Chairman of the Board, Chief Executive Officer  and President*** |

 

Pursuant to the requirements of the SecuritiesExchange Act of 1934, this Report has been signed below by the followingpersons on behalf of Constellation Energy Group, Inc., the Registrant, andin the capacities and on the dates indicated.
|                                             | **Signature** | ** ** | ** ** | ** **                     | **Title** | ** **                              | ** ** | ** **              | **Date** | ** ** |
|---------------------------------------------|---------------|------------|------------|--------------------------------|-----------|-----------------------------------------|------------|-------------------------|----------|------------|
| Principal executive officer and director:   |          |       |       |                           |
| By                                          |          | /s/        |       | M. A. Shattuck III             |      | Chairman of  the Board, Chief Executive |       | February 27,  2007 |
|                                        |          |       | ** ** | **M.  A. Shattuck III**        |      | Officer, President and Director         |       |                    |
| Principal financial and accounting officer: |          |       |       |                           |
| By                                          |          | /s/        |       | E. F. Smith                    |      | Executive  Vice President, Chief        |       | February 27,  2007 |
|                                        |          |       | ** ** | **E.  F. Smith**               |      | Financial Officer, and Chief            |       |                    |
|                                        |          |       |       |                           |      | Administrative Officer                  |       |                    |
| Directors:                                  |          |       |       |                           |
| /s/                                         |          |       |       | Y. C. de Balmann               |      | Director                                |       | February 27,  2007 |
|                                        | ** **    |       |       | **Y.  C. de Balmann**          |      |                                    |       |                    |
| /s/                                         |          |       |       | D. L. Becker                   |      | Director                                |       | February 27,  2007 |
|                                        | ** **    |       |       | **D.  L. Becker**              |      |                                    |       |                    |
| /s/                                         |          |       |       | J. T. Brady                    |      | Director                                |       | February 27,  2007 |
|                                        | ** **    |       |       | **J.  T. Brady**               |      |                                    |       |                    |
| /s/                                         |          |       |       | J. R. Curtiss                  |      | Director                                |       | February 27,  2007 |
|                                        | ** **    |       |       | **J.  R. Curtiss**             |      |                                    |       |                    |
| /s/                                         |          |       |       | F. A. Hrabowski, III      |      | Director                                |       | February 27,  2007 |
|                                        | ** **    |       |       | **F.  A. Hrabowski, III** |      |                                    |       |                    |
| /s/                                         |          |       |       | N. Lampton                     |      | Director                                |       | February 27,  2007 |
|                                        | ** **    |       |       | **N.  Lampton**                |      |                                    |       |                    |
| /s/                                         |          |       |       | R. J. Lawless                  |      | Director                                |       | February 27,  2007 |
|                                        | ** **    |       |       | **R.  J. Lawless**             |      |                                    |       |                    |
| /s/                                         |          |       |       | M. D. Sullivan                 |      | Director                                |       | February 27,  2007 |
|                                        | ** **    |       |       | **M. D.  Sullivan**            |      |                                    |       |                    |
|                                             |               |            |            |                                |           |                                         |            |                         |          |            |  |  |  |  |

 

129

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Pursuant to the requirements of Section 13 or 15(d) of theSecurities Exchange Act of 1934, Baltimore Gas and Electric Company, theRegistrant, has duly caused this Report to be signed on its behalf by theundersigned, thereunto duly authorized.
|                   |     | BALTIMORE GAS AND ELECTRIC COMPANY  (REGISTRANT) |
|-------------------|----------|--------------------------------------------------|
|              |     |
| February 27, 2007 | By  | /s/                                              |   | KENNETH W. DEFONTES, JR. |   |
|              |     | *** ***                                     |   | **Kenneth  W. DeFontes, Jr.*President and Chief Executive Officer*** |   |
|                   |          |                                                  |  |  |  |  |

 

Pursuant to the requirements of theSecurities Exchange Act of 1934, this Report has been signed below by thefollowing persons on behalf of Baltimore Gas and Electric Company, theRegistrant, and in the capacities and on the dates indicated.
|                                                          | **Signature** | ** ** | ** ** | ** **               | **Title** | ** **                      | ** ** | ** **              | **Date** | ** ** |
|----------------------------------------------------------|---------------|------------|------------|--------------------------|-----------|---------------------------------|------------|-------------------------|----------|------------|
| Principal executive officer and director:                |          |       |       |                     |
| By                                                       |          | /s/        |       | K. W. DeFontes, Jr.      |      | President,  Chief Executive     |       | February 27,  2007 |
|                                                     |          |       | ** ** | **K.  W. DeFontes, Jr.** |      | Officer, and Director           |       |                    |
| Principal financial and accounting officer and director: |          |       |       |                     |
| By                                                       |          | /s/        |       | E. F. Smith              |      | Senior Vice  President, Chief   |       | February 27,  2007 |
|                                                     |          |       | ** ** | **E.  F. Smith**         |      | Financial Officer, and Director |       |                    |
| Directors:                                               |          |       |       |                     |
|                                                     |          | /s/        |       | M. A. Shattuck III       |      | Director                        |       | February 27,  2007 |
|                                                     | ** **    |       |       | **M. A.  Shattuck III**  |      |                            |       |                    |
|                                                          |               |            |            |                          |           |                                 |            |                         |          |            |  |  |  |  |

 

130

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**EXHIBITINDEX**
|       | **Exhibit  Number** | ** ** | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                | ** ** | ** ** |
|-------|---------------------|------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------|
| *2    |                | —     |       | Agreement and Plan of Share Exchange between Baltimore Gas and  Electric Company and Constellation Energy Group, Inc. dated as of  February 19, 1999. (Designated as Exhibit No. 2 to the Registration  Statement on Form S-4 dated March 3, 1999, File No. 33-64799.)                                                                                                                                                                                                                                                                                                 |
| *2(a) |                | —     |       | Agreement and Plan of Reorganization and Corporate Separation  (Nuclear). (Designated as Exhibit No. 2(a) to the Current  Report on Form 8-K dated July 7, 2000, File Nos. 1-12869  and 1-1910.)                                                                                                                                                                                                                                                                                                                                                                            |
| *2(b) |                | —     |       | Agreement and Plan of Reorganization and Corporate Separation  (Fossil). (Designated as Exhibit No. 2(b) to the Current  Report on Form 8-K dated July 7, 2000, File Nos. 1-12869  and 1-1910.)                                                                                                                                                                                                                                                                                                                                                                             |
| *2(c) |                | —     |       | Purchase and Sale Agreement by and between Constellation  Power, Inc. and TPF Generation Holdings, LLC dated as of  October 10, 2006. (Designated as  Exhibit 2(a) to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                      |
| *2(d) |                | —     |       | Termination and Release Agreement, dated October 24, 2006, by  and among Constellation Energy Group, Inc., FPL Group, Inc. and CF  Merger Corporation (Designated as Exhibit 2.1 to the Current Report on  Form 8-K dated October 25, 2006, File Nos. 1-12869 and  1-1910.)                                                                                                                                                                                                                                                                                                 |
| *3(a) |                | —     |       | Articles of Amendment and Restatement of the Charter of Constellation  Energy Group, Inc. as of April 30, 1999. (Designated as  Exhibit No. 99.2 to the Current Report on Form 8-K dated  April 30, 1999, File No. 1-1910.)                                                                                                                                                                                                                                                                                                                                            |
| *3(b) |                | —     |       | Articles Supplementary to the Charter of Constellation Energy  Group, Inc., as of July 19, 1999. (Designated as  Exhibit No. 3(a) to the Quarterly Report on Form 10-Q  for the quarter ended June 30, 1999, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                                                       |
| *3(c) |                | —     |       | Certificate of Correction to the Charter of Constellation Energy  Group, Inc. as of September 13, 1999. (Designated as  Exhibit No. 3(c) to the Annual Report on Form 10-K  for the year ended December 31, 1999, File Nos. 1-12869  and 1-1910.)                                                                                                                                                                                                                                                                                                            |
| *3(d) |                | —     |       | Charter of BGE, restated as of August 16, 1996. (Designated as  Exhibit No. 3 to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 1996, File No. 1-1910.)                                                                                                                                                                                                                                                                                                                                                                                             |
| *3(e) |                | —     |       | Articles Supplementary to the Charter of Constellation Energy  Group, Inc. as of November 20, 2001. (Designated as  Exhibit No. 3(e) to the Annual Report on Form 10-K  for the year ended December 31, 2001, File Nos. 1-12869  and 1-1910.)                                                                                                                                                                                                                                                                                                                |
| *3(f) |                | —     |       | Bylaws of Constellation Energy Group, Inc., as amended to October 20,  2006. (Designated as Exhibit 3(a) to the Quarterly Report on  Form 10-Q for the quarter ended September 30, 2006, File  Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                                                                               |
| *3(g) |                | —     |       | Bylaws of BGE, as amended to October 16, 1998. (Designated as  Exhibit No. 3 to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 1998, File No. 1-1910.)                                                                                                                                                                                                                                                                                                                                                                                              |
| *4(a) |                | —     |       | Indenture between Constellation Energy Group, Inc. and the Bank  of New York, Trustee dated as of March 24, 1999. (Designated as  Exhibit No. 4(a) to the Registration Statement on Form S-3  dated March 29, 1999, File No. 333-75217.)                                                                                                                                                                                                                                                                                                                          |
| *4(b) |                | —     |       | First Supplemental Indenture between Constellation Energy  Group, Inc. and the Bank of New York, Trustee dated as of  January 24, 2003. (Designated as Exhibit No. 4(b) to the  Registration Statement on Form S-3 dated January 24, 2003,  File No. 333-102723.)                                                                                                                                                                                                                                                                                                 |
| *4(c) |                | —     |       | Supplemental Indenture between BGE and Bankers Trust Company, as  Trustee, dated as of June 20, 1995, supplementing, amending and  restating Deed of Trust dated February 1, 1919. (Designated as  Exhibit No. 4 to the Quarterly Report on Form 10-Q for  the quarter ended June 30, 1995, File No. 1-1910); as  supplemented by Supplemental Indentures dated as of June 15, 1996  (Designated as Exhibit No. 4 to the Quarterly Report on  Form 10-Q for the quarter ended June 30, 1996,) and as of  June 26, 2000 (filed herewith). |

131

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| *4(d)  |   | — |   | Indenture dated July 1, 1985, between BGE and The Bank of New  York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee.  (Designated as Exhibit 4(a) to the Registration Statement on  Form S-3, File No. 2-98443); as supplemented by  Supplemental Indentures dated as of October 1, 1987 (Designated as  Exhibit 4(a) to the Current Report on Form 8-K, dated  November 13, 1987, File No. 1-1910) and as of  January 26, 1993 (Designated as Exhibit 4(b) to the Current  Report on Form 8-K, dated January 29, 1993, File No. 1-1910.) |
|--------|--------|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *4(e)  |   | — |   | Form of Subordinated Indenture between the Company and The Bank  of New York, as Trustee in connection with the issuance of the Junior  Subordinated Debentures. (Designated as Exhibit 4(d) to the  Registration Statement on Form S-3 dated August 5, 2003, File  No. 333-107681.)                                                                                                                                                                                                                                                                                                                               |
| *4(f)  |   | — |   | Form of Supplemental Indenture between the Company and The Bank  of New York, as Trustee in connection with the issuances of the Junior  Subordinated Debentures. (Designated as Exhibit 4(e) to the  Registration Statement on Form S-3 dated August 5, 2003, File  No. 333-107681.)                                                                                                                                                                                                                                                                                                                              |
| *4(g)  |   | — |   | Form of Preferred Securities Guarantee (Designated as  Exhibit 4(f) to the Registration Statement on Form S-3  dated August 5, 2003, File No. 333-107681.)                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| *4(h)  |   | — |   | Form of Junior Subordinated Debenture (Designated as  Exhibit 4(h) to the Registration Statement on Form S-3  dated August 5, 2003, File No. 333-107681.)                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| *4(i)  |   | — |   | Form of Amended and Restated Declaration of Trust (including  Form of Preferred Security) (Designated as Exhibit 4(c) to the  Registration Statement on Form S-3 dated August 5, 2003, File  No. 333-107681.)                                                                                                                                                                                                                                                                                                                                                                                                 |
| *4(j)  |   | — |   | Indenture dated as of July 24, 2006 between Constellation Energy  Group, Inc. and Deutsche Bank Trust Company Americas, as trustee.  (Designated as Exhibit 4(a) to the Registration Statement on  Form S-3 filed July 24, 2006, File No. 333-135991.)                                                                                                                                                                                                                                                                                                                                                        |
| *4(k)  |   | — |   | Indenture dated as of July 24, 2006 between Baltimore Gas and  Electric Company and Deutsche Bank Trust Company Americas, as trustee.  (Designated as Exhibit 4(b) to the Registration Statement on  Form S-3 filed July 24, 2006, File No. 333-135991.)                                                                                                                                                                                                                                                                                                                                                           |
| *4(l)  |   | — |   | First Supplemental Indenture between Baltimore Gas and Electric  Company and Deutsche Bank Trust Company Americas, as trustee, dated as of  October 13, 2006. (Designated as  Exhibit 4(a) to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                                          |
| *4(m)  |   | — |   | Registration Rights Agreement dated October 13, 2006 among  Baltimore Gas and Electric Company and the parties named therein relating to  5.90% Notes due 2016. (Designated as  Exhibit 4(b) to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                                        |
| *4(n)  |   | — |   | Registration Rights Agreement dated October 13, 2006 among  Baltimore Gas and Electric Company and the parties named therein relating to  6.35% Notes due 2036. (Designated as  Exhibit 4(c) to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                                        |
| *10(a) |   | — |   | Executive Annual Incentive Plan of Constellation Energy  Group, Inc., as amended and restated. (Designated as  Exhibit No. 10(a) to the Quarterly Report on Form 10-Q  for the quarter ended March 31, 2004, File Nos. 1-12869  and 1-1910.)                                                                                                                                                                                                                                                                                                                                                             |
| *10(b) |   | — |   | Constellation Energy Group, Inc. 1995 Long-Term Incentive  Plan, as amended and restated. (Designated as Exhibit No. 10(b) to  the Quarterly Report on Form 10-Q for the quarter ended  September 30, 2004, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                                                                                               |
| *10(c) |   | — |   | Constellation Energy Group, Inc. Nonqualified Deferred  Compensation Plan, as amended and restated. (Designated as Exhibit No. 10(c) to  the Annual Report on Form 10-K for the year ended  December 31, 2002, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                                                                                            |
| *10(d) |   | — |   | Constellation Energy Group, Inc. Deferred Compensation Plan for  Non-Employee Directors, as amended and restated. (Designated as Exhibit 10(a) to  the Quarterly Report on Form 10-Q for the Quarter ended  September 30, 2006, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                                                                                     |

132

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| *10(e) |   | — |   | Compensation agreements between Constellation Energy Group, Inc.  and E. Follin Smith (Attachment 1—Employment Agreement; Attachment  2—Severance Agreement (Attachment 2 superseded by amended and restated change  in control severance agreement filed as Exhibit 10(y) to the Annual  Report on Form 10-K for the year ended December 31,  2005.)(Designated as Exhibit 10(c) to the Quarterly Report on  Form 10-Q for the quarter ended June 30, 2004, File  Nos. 1-12869 and 1-1910.) |
|--------|--------|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *10(f) |   | — |   | Amended and restated change in control severance agreement between  Constellation Energy Group, Inc. and Thomas V. Brooks. (Designated as  Exhibit 10(f) to the Annual Report on Form 10-K for the  year ended December 31, 2005.)                                                                                                                                                                                                                                                                                                   |
| *10(g) |   | — |   | Grantor Trust Agreement Dated as of February 27, 2004 between  Constellation Energy Group, Inc. and Citibank, N.A. (Designated as  Exhibit No. 10(d) to the Quarterly Report on Form 10-Q  for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                        |
| *10(h) |   | — |   | Amended and restated change in control severance agreement between  Constellation Energy Group, Inc. and Mayo A. Shattuck III. (Designated  as Exhibit 10.2 to the Current Report on Form 8-K dated  December 19, 2005, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                               |
| *10(i) |   | — |   | Grantor Trust Agreement dated as of February 27, 2004 between  Constellation Energy Group, Inc. and T. Rowe Price Trust Company.  (Designated as Exhibit No. 10(b) to the Quarterly Report on  Form 10-Q for the quarter ended June 30, 2004, File  Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                         |
| *10(j) |   | — |   | Constellation Energy Group, Inc. Benefits Restoration Plan, as  amended and restated. (Designated as Exhibit No. 10(m) to the  Annual Report on Form 10-K for the year ended December 31,  2001, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                       |
| *10(k) |   | — |   | Constellation Energy Group, Inc. Supplemental Pension Plan, as  amended and restated. (Designated as Exhibit No. 10(d) to the  Quarterly Report on Form 10-Q for the quarter ended March 31,  2004, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                    |
| *10(l) |   | — |   | Constellation Energy Group, Inc. Senior Executive Supplemental  Plan, as amended and restated. (Designated as  Exhibit No. 10(e) to the Quarterly Report on Form 10-Q  for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                |
| *10(m) |   | — |   | Constellation Energy Group, Inc. Supplemental Benefits Plan, as  amended and restated. (Designated as Exhibit No. 10(p) to the  Annual Report on Form 10-K for the year ended December 31,  2001, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                      |
| *10(n) |   | — |   | Constellation Energy Group, Inc. Executive Long-Term  Incentive Plan, as amended and restated. (Designated as  Exhibit 10(b) to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                     |
| 10(o)  |   | — |   | Constellation Energy Group, Inc. 2002 Executive Annual Incentive  Plan, as amended and restated.                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| *10(p) |   | — |   | Constellation Energy Group, Inc. 2002 Senior Management Long-Term  Incentive Plan, as amended and restated. (Designated as  Exhibit 10(c) to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                        |
| *10(q) |   | — |   | Constellation Energy Group, Inc. Management Long-Term  Incentive Plan, as amended and restated. (Designated as  Exhibit 10(d) to the Quarterly Report on Form 10-Q for  the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                                    |
| *10(r) |   | — |   | Summary of Constellation Energy Group, Inc. Board of Directors  Non-Employee Director Compensation Program. (Designated as  Exhibit 10(x) to the Annual Report on Form 10-K for the  year ended December 31, 2004, File Nos. 1-12869 and 1-1910.)                                                                                                                                                                                                                                                                               |
| *10(s) |   | — |   | Amended and restated change in control severance agreement between  Constellation Energy Group, Inc. and E. Follin Smith. (Designated as  Exhibit 10(f) to the Annual Report on Form 10-K for the  year ended December 31, 2005.)                                                                                                                                                                                                                                                                                                    |
| 10(t)  |   | — |   | Constellation Energy Group, Inc. 2007 Long-Term Incentive Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 12(a)  |   | — |   | Constellation Energy Group, Inc. and Subsidiaries Computation of  Ratio of Earnings to Fixed Charges.                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 12(b)  |   | — |   | Baltimore Gas and Electric Company and Subsidiaries Computation of  Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to  Combined Fixed Charges and Preferred and Preference Dividend Requirements.                                                                                                                                                                                                                                                                                                                                    |

133

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| 21    |   | — |   | Subsidiaries of the Registrant.                                                                                                                                                                                                               |
|-------|--------|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 23    |   | — |   | Consent of PricewaterhouseCoopers LLP, Independent Registered Public  Accounting Firm.                                                                                                                                                        |
| 31(a) |   | — |   | Certification of Chairman of the Board, Chief Executive Officer and  President of Constellation Energy Group, Inc. pursuant to  Section 302 of the Sarbanes-Oxley Act of 2002.                                                      |
| 31(b) |   | — |   | Certification of Executive Vice President, Chief Financial Officer  and Chief Administrative Officer of Constellation Energy Group, Inc.  pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                |
| 31(c) |   | — |   | Certification of President and Chief Executive Officer of Baltimore  Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002.                                                                                |
| 31(d) |   | — |   | Certification of Senior Vice President and Chief Financial Officer of  Baltimore Gas and Electric Company pursuant to Section 302 of the  Sarbanes-Oxley Act of 2002.                                                                    |
| 32(a) |   | — |   | Certification of Chairman of the Board, Chief Executive Officer and  President of Constellation Energy Group, Inc. pursuant to 18 U.S.C.  Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley  Act of 2002. |
| 32(b) |   | — |   | Certification of Executive Vice President and Chief Financial Officer  of Constellation Energy Group, Inc. pursuant to 18 U.S.C.  Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley  Act of 2002.         |
| 32(c) |   | — |   | Certification of President and Chief Executive Officer of Baltimore Gas  and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                            |
| 32(d) |   | — |   | Certification of Senior Vice President and Chief Financial Officer of  Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350,  as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of  2002.               |

*                      Incorporatedby Reference.

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