Edgar Filing: BALTIMORE GAS & ELECTRIC CO

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.

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended DECEMBER 31, 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)

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

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

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

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

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

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

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

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

Large accelerated filer x Accelerated filer o Non-accelerated filer o

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

Large accelerated filer o Accelerated filer o Non-accelerated filer x

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

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

CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE
180,679,592 SHARES OUTSTANDING ON JANUARY 31, 2007.

DOCUMENTS INCORPORATED BY REFERENCE

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

TABLE OF CONTENTS

			Page
		Forward Looking Statements	1
PART I
Item 1	—	Business	2
		Overview	2
		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

Forward Looking Statements

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

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

¨ the liquidity and competitiveness of wholesale markets for energy commodities,

¨ the effect of weather and general economic and business conditions on energy supply, demand, and prices,

¨ the ability to attract and retain customers in our competitive supply activities and to adequately forecast their energy usage,

¨ the timing and extent of deregulation of, and competition in, the energy markets, and the rules and regulations adopted on a transitional basis in those markets,

¨ uncertainties associated with estimating natural gas reserves, developing properties, and extracting natural gas,

¨ regulatory or legislative developments that affect deregulation, transmission or distribution rates and revenues, demand for energy, or increases in costs, including costs related to nuclear power plants, safety, or environmental compliance,

¨ the inability of Baltimore Gas and Electric Company (BGE) to recover all its costs associated with providing customers service,

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

¨ the effectiveness of Constellation Energy’s and BGE’s risk management policies and procedures and the ability and willingness of our counterparties to satisfy their financial and performance commitments,

¨ operational factors affecting commercial operations of our generating facilities (including nuclear facilities) and BGE’s transmission and distribution facilities, including catastrophic weather-related damages, unscheduled outages or repairs, unanticipated changes in fuel costs or availability, unavailability of coal or gas transportation or electric transmission services, workforce issues, terrorism, liabilities associated with catastrophic events, and other events beyond our control,

¨ the actual outcome of uncertainties associated with assumptions and estimates using judgment when applying critical accounting policies and preparing financial statements, including factors that are estimated in determining the fair value of energy contracts, such as the ability to obtain market prices and, in the absence of verifiable market prices, the appropriateness of models and model inputs (including, but not limited to, estimated contractual load obligations, unit availability, forward commodity prices, interest rates, correlation and volatility factors),

¨ changes in accounting principles or practices,

¨ losses on the sale or write down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets,

¨ the ability to successfully identify and complete acquisitions and sales of businesses and assets, and

¨ cost and other effects of legal and administrative proceedings that may not be covered by insurance, including environmental liabilities.

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

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

PART I

Item 1. Business

Overview

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

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

Our merchant energy business is a competitive provider of energy solutions for a variety of customers. It has electric generation assets located in various regions of the United States and provides energy solutions to meet customers’ needs. Our merchant energy business focuses on serving the energy and capacity requirements (load-serving) of, and providing other energy products and risk management services, for various customers.

Our merchant energy business includes:

¨ a generation operation that owns, operates, and maintains fossil, nuclear, and hydroelectric generating facilities and holds interests in qualifying facilities, fuel processing facilities and power projects in the United States,

¨ a wholesale marketing, risk management, and trading operation that primarily provides energy products and services to distribution utilities, power generators, and other wholesale customers,

¨ an electric and natural gas retail operation that provides energy products and services to commercial, industrial, and governmental customers, and

¨ a generation operations and maintenance services operation.

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

Our other nonregulated businesses:

¨ design, construct, and operate heating, cooling, and cogeneration facilities, and provide various energy-related services, including energy consulting, for commercial, industrial, and governmental customers throughout North America, and

¨ provide home improvements, service heating, air conditioning, plumbing, electrical, and indoor air quality systems, and provide natural gas to residential customers in central Maryland.

On October 24, 2006, Constellation Energy and FPL Group, Inc. (FPL Group) agreed to terminate 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 have impacted us, our strategy, and the seasonality of our business, please refer to Item 7. Management’s Discussion and Analysis section.

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

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

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

Operating Segments

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

	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 been reclassified to conform with the current year’s presentation.

(1) Excludes income from discontinued operations in 2006, 2005 and 2004 and cumulative effects of changes in accounting principles in 2005 as discussed in more detail in Item 8. Financial Statements and Supplementary Data.

Merchant Energy Business

Introduction

Our merchant energy business integrates electric generation assets with the marketing and risk management of energy and energy-related commodities, allowing us to manage energy price risk over geographic regions and time.

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

Constellation Generation Group, our merchant generation operation, oversees the ownership, operations, maintenance, and performance of our fossil, nuclear and renewable generation and fuel processing facilities. Our generation capacity supports our wholesale and retail operations by providing a source of reliable power supply. Constellation Generation Group also owns and operates a generation operations and maintenance services organization.

Our merchant energy business:

¨ provided approximately 34,650 megawatts (MW) of peak load in the aggregate to distribution utilities, municipalities, commercial, industrial, and governmental customers during 2006,

¨ provided approximately 355,000 million British Thermal Units (mmBTUs) of natural gas to commercial, industrial, and governmental customers during 2006,

¨ delivered 26.0 million tons of coal to international and domestic third-party customers and to our own fleet during 2006, and

¨ managed approximately 8,680 MW of generation capacity as of December 31, 2006.

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

¨ Mid-Atlantic Region—our fossil, nuclear, and hydroelectric generating facilities and load-serving activities in the PJM Interconnection (PJM) region. This also includes active portfolio management of generating assets and other physical and financial contractual arrangements, as well as other PJM competitive supply activities. In addition, due to the expiration of its power purchase agreement, beginning in June 2006 until its sale in December 2006, the results of our University Park generating facility are included with the Mid-Atlantic Region. University Park was previously included in Plants with Power Purchase Agreements.

¨ Plants with Power Purchase Agreements—our generating facilities outside the Mid-Atlantic Region with long-term power purchase agreements. As discussed in Note 2 to Consolidated Financial Statements, the sale of the High Desert facility resulted in a reclassification of its results to discontinued operations.

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

¨ Retail Competitive Supply—our operation that provides electric and natural gas energy products and services to commercial, industrial, and governmental customers.

¨ Other—our investments in qualifying facilities and domestic power projects and our generation operations and maintenance services.

In December 2006, we completed the sale of 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

We discuss the sale of these gas-fired generating facilities in Note 2 to Consolidated Financial Statements.

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

Mid-Atlantic Region

We own 6,305 MW of fossil, nuclear, and hydroelectric generation capacity in the Mid-Atlantic Region. The output of these plants is managed by our wholesale marketing, risk management, and trading operation and is hedged through a combination of power sales to wholesale and retail market participants. Our merchant energy business meets the load-serving requirements of various contracts using the output from the Mid-Atlantic Region and from purchases in the wholesale market.

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

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

Plants with Power Purchase Agreements

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

We own 100% of Nine Mile Point Unit 1 (620 MW) and 82% of Unit 2 (933 MW). The remaining interest 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 located within the New York Independent System Operator (NYISO) region.

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

After termination of the power purchase agreements, a revenue sharing agreement with the former owners of the plant will begin and continue through 2021. Under this agreement, which applies only to our ownership percentage of Unit 2, a predetermined price is compared to the market price for electricity. If the market price exceeds the strike price, then 80% of this excess amount is shared with the former owners of the plant. The average strike price for the first year of the revenue sharing agreement is $40.75 per MWH. The strike price increases two percent annually beginning in the second year of the revenue sharing agreement. The revenue sharing agreement is unit contingent and is based on the operation of the unit.

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

In October 2006, we received Nuclear Regulatory Commission (NRC) approval for license extension for both units at our Nine Mile Point nuclear facility. With the renewed licenses, 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 MW reactor that entered service in 1970 and is licensed to operate until 2029. We sell up to 90% of the plant’s output and capacity to the former owners for 10 years at an average price of $44.00 per MWH under a long term unit contingent power purchase agreement. The remaining output is managed by our wholesale marketing, risk management, and trading operation and sold into the wholesale market. During the fourth quarter of 2006, we completed a planned outage at our Ginna nuclear facility, which included increasing the capacity of the 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 the former owners.

Competitive Supply

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

Wholesale and Retail Load-Serving Activities

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

Our retail competitive supply operation structures transactions to supply full energy and capacity requirements and provide natural gas, transportation, and other energy products and services to retail, commercial, industrial, and governmental customers.

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

¨ bilateral power and natural gas purchase agreements with third parties,

¨ unit contingent purchases from generation companies,

¨ our generation assets,

¨ regional power pools,

¨ tolling contracts with generation companies, which provide us the right, but not the obligation, to purchase power at a price linked to the variable cost of production, including fuel, with terms that generally extend from several months to several years, but can be longer, and

¨ exchange traded electricity and natural gas contracts.

Portfolio Management and Trading

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

Our wholesale marketing, risk management, and trading operation actively uses energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions. We use both derivative and nonderivative contracts in managing our portfolio of energy sales and purchase contracts. Generally, we expect to use both derivative and nonderivative contracts to hedge a majority of our portfolio over a three-year period in order to reduce volatility in our results. Although a substantial portion of our portfolio is hedged, we are able to identify opportunities to deploy risk capital to increase the value of our accrual positions, which we characterize as portfolio management.

We trade energy and energy-related commodities and deploy risk capital in the management of our portfolio in order to earn additional returns. These activities are managed through daily value at risk and stop loss limits and liquidity guidelines, and could have a material impact on our financial results. We discuss the impact of our trading activities and value at risk in more detail in Item 7. Management’s Discussion and Analysis.

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

¨ forward contracts (which commit us to purchase or sell energy commodities in the future),

¨ swap agreements (which require payments to or from counterparties based upon the difference between two prices for a predetermined contractual (notional) quantity),

¨ option contracts (which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price), and

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

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

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

¨ provide fixed-price energy commitments to customers and suppliers,

¨ reduce exposure to the volatility of market prices, and

¨ hedge fuel requirements at our non-nuclear generation facilities.

Coal and International Services

Our wholesale marketing, risk management, and trading operation participates in global coal sourcing activities by providing coal and coal-related logistical services, for the variable or fixed supply needs of global customers. In 2006, we delivered 26.0 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 fuel processing facility in South Carolina.

We will continue to evaluate new international opportunities, including expanding our coal sourcing, freight, and power, natural gas and emissions activities outside of the United States.

Natural Gas Services

Our wholesale marketing, 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 downstream activities include providing natural gas to various customers, including large utilities, industrial customers, power generators, wholesale marketers, and retail aggregators.

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

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

Other

We hold up to a 50% voting interest in 24 operating energy projects that consist of electric generation (primarily relying on alternative fuel sources), fuel processing, or fuel handling facilities. These generating projects are considered qualifying facilities under the Public Utility Regulatory Policies Act of 1978. Each electric generating plant sells its output to a local utility under long-term contracts.

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

UniStar Nuclear

In 2005, we formed UniStar Nuclear, LLC (UniStar), a joint enterprise with AREVA NP, Inc., to develop the business model for a standardized fleet of nuclear power plants based 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 to license, construct, own, and operate U.S. EPR plants.

UniStar also offers the business framework that could enable the development of future joint ventures with Constellation Energy, other energy companies, and interested parties. 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 nuclear power plants, our financial commitment will be limited to the formation of the business platform and business development activities, including licensing and permit activities and securing access to long-lead materials such as heavy forgings needed for reactor pressure vessels and steam generators or turbine and generator parts.

Fuel Sources

Our power plants use diverse fuel sources. Our fuel mix based on capacity owned at December 31, 2006 and our generation based on actual output 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			—

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

(1) Includes solar, geothermal, hydro, waste coal and biomass.

(2) Switches between natural gas and oil.

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

Nuclear

The output at our nuclear facilities over the past 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 proportionate ownership interest

The supply of fuel for nuclear generating stations includes the:

¨ purchase of uranium (concentrates and uranium hexafluoride),

¨ conversion of uranium concentrates to uranium hexafluoride,

¨ enrichment of uranium hexafluoride, and

¨ fabrication of nuclear fuel assemblies.

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.

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 uranium and conversion are increasing, we do not anticipate any significant problems in meeting our future requirements.

Storage of Spent Nuclear Fuel—Federal Facilities

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

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

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

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

Storage of Spent Nuclear Fuel—On-Site Facilities

Calvert Cliffs has a license from the NRC to operate an on-site independent spent fuel storage installation that expires in 2012. We have storage capacity at Calvert Cliffs that will accommodate spent fuel from operations through 2011. In addition, we can expand our temporary storage capacity at Calvert Cliffs to meet future requirements until approximately 2025. Nine Mile Point and Ginna are beginning initial planning studies for the potential development of independent spent fuel storage capacity. Nine Mile Point’s Unit 1 has sufficient storage capacity within the plant until 2011. Nine Mile Point’s Unit 2 has sufficient storage capacity within the plant until 2012. Ginna has sufficient storage capacity within the plant until 2010.

Cost for Decommissioning Uranium Enrichment Facilities

The Energy Policy Act of 1992 requires domestic nuclear utilities to contribute to a fund for decommissioning and decontaminating uranium enrichment facilities that had been operated by DOE. These contributions are generally payable over a 15-year period with escalation for inflation and are based upon the amount of uranium enriched by DOE for each utility through 1992. The 1992 Act provides that these costs are recoverable through utility service rates. BGE is solely responsible for these costs as they relate to Calvert Cliffs and made the last payment in 2006. The sellers of the Nine Mile Point plant and the Long Island Power Authority 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 nuclear plants at the time these plants cease operation. Every two years, the NRC requires us to demonstrate reasonable assurance that funds will be available to decommission the sites. When BGE transferred all of its nuclear generating assets to our merchant energy business, it also transferred the trust fund established to pay for decommissioning Calvert Cliffs. At December 31, 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, BGE ratepayers must pay a total of $520 million, in 1993 dollars adjusted for inflation, to decommission Calvert Cliffs through fixed annual collections. In 2006, BGE received approval from the Maryland PSC to continue annual customer collections of approximately $18.7 million through December 31, 2016. BGE will be required to submit a filing to determine the level of customer contributions after December 31, 2016.

BGE is collecting this amount on behalf of Calvert Cliffs. Any costs to decommission Calvert Cliffs in excess of this $520 million must be paid by Calvert Cliffs. If BGE ratepayers have paid more than this amount at the time of decommissioning, Calvert Cliffs must refund the excess. If the cost to decommission Calvert Cliffs is less than the $520 million BGE’s ratepayers are 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 enacted in June 2006, requires BGE to provide credits to residential electric customers equal to the amount collected for decommissioning annually for 10 years beginning January 1, 2007. Under the provisions of Senate Bill 1 we are required to apply the collection of the nuclear decommissioning trust funds over the ten year period beginning January 1, 2007 toward the fulfillment of the decommissioning obligations of BGE ratepayers.

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

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

Coal

We purchase the majority of our coal for electric generation under supply contracts with mining operators, and we acquire the remainder in the spot or forward coal markets. We believe that we will be able to renew supply contracts as they expire or enter into contracts with other coal suppliers. Our primary coal burning facilities have the following requirements:

	Approximate Annual Coal Requirement (tons)		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. Over the past few years, we expanded our coal sources including restructuring our rail contracts, increasing the range of coals we can consume, adding synthetic fuel as an alternate source, and finding potential other coal supply sources including shipments from various international sources. While we primarily use coal produced from mines located in central and northern Appalachia, we are capable of switching to imported coals to manage our coal supply. The timely delivery of coal together with the maintenance of appropriate levels of inventory is necessary to allow for continued, reliable generation from these facilities.

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

The annual coal requirements for the ACE, Jasmin, and Poso plants, which are located in California, are supplied under contracts with mining operators. The Jasmin and Poso plants are restricted to coal with sulfur content less than 4.0% and ACE is restricted to less than 2.0%.

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

Gas

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

Oil

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

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

Competition

Market developments over the past several years have changed the nature of competition in the merchant energy business. Certain companies within the merchant energy sector have curtailed their activities or withdrawn completely from the business. However, new competitors (e.g., financial investors, banks and investment banks) have entered the market. We encounter competition from companies of various sizes, having varying levels of experience, financial and human resources, and differing strategies.

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

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

States are considering different types of regulatory initiatives concerning competition in the power industry, which makes a competitive assessment difficult. Increased competition that resulted from some of these initiatives in several states contributed in some instances to a reduction in electricity prices and put pressure on electric utilities to lower their costs, including the cost of purchased electricity. While many states continue to support retail competition and industry restructuring, other states that were considering deregulation have slowed their plans or postponed consideration of deregulation. In addition, other states are reconsidering deregulation.

We believe there is adequate growth potential in the current deregulated market and that further market changes could provide additional opportunities for our merchant energy business. In addition, our wholesale marketing, risk management, and trading operation participates in global coal sourcing activities by providing coal for the variable or fixed supply needs of North American and international power generators. In addition, our wholesale marketing, risk management, and trading operation includes upstream (exploitation and production) and downstream (transportation and storage) natural gas operations.

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

Merchant Energy Operating Statistics

	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 until sale in December 2006.

Operating statistics do not reflect the elimination of intercompany transactions.

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

Baltimore Gas and Electric Company

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

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

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

Electric Business

Electric Regulatory Matters and Competition

Deregulation

Effective July 1, 2000, electric customer choice and competition among electric suppliers was implemented in Maryland. As a result of the deregulation of electric generation, all customers can choose their electric energy supplier. While BGE does not sell electric commodity to all customers in its service territory, BGE continues to deliver electricity to all customers and provides meter reading, billing, emergency response, and regular maintenance.

Standard Offer Service

BGE provided fixed-price standard offer service to commercial and industrial customers through either June 30, 2002 or June 30, 2004, depending on customer type, and for residential customers through June 30, 2006.

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

Provider of Last Resort

BGE is obligated to provide market-based standard offer service to all of its electric customers for varying periods. The POLR rates charged recover BGE’s wholesale power supply costs and include an administrative fee. The administrative fee includes a shareholder return component and an incremental cost component. As a result of Senate Bill 1, beginning January 1, 2007, the shareholder return component of the administrative charge for residential POLR service was suspended. We discuss Senate Bill 1 in detail in the Residential Customers section.

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

Commercial and Industrial Customers

BGE is obligated to provide market-based standard offer service to commercial and 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 of Maryland utilities to provide POLR service for those commercial and industrial customers for which market-based standard offer service was scheduled to expire at the end of May 2007. The extended service will be provided on substantially the same terms as under the existing service, except that wholesale bidding for service to some customers will be conducted more frequently.

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

Residential Customers

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

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

¨ allows BGE to recover the costs deferred from July 1, 2006 to May 31, 2007 from its customers over a period not to exceed 10 years, on terms and conditions to be determined by the Maryland PSC, including through the issuance of rate stabilization bonds that securitize the deferred costs;

¨ directs the Maryland PSC to investigate measures to mitigate the impact of residential rate increases on BGE customers, including by investigating the prior determination of and allowances for stranded costs that occurred when BGE transferred assets to its affiliates in 2000 and by requiring the Maryland PSC to provide funds to residential customers of BGE for mitigation of BGE’s rate increases, including any adjustment in favor of BGE’s customers to allowances for such stranded costs; and

¨ requires BGE to reduce residential electric rates by approximately $39 million per year for 10 years, beginning January 1, 2007, through suspension of the collection of the residential return component of the administrative charge for POLR service and a credit equal to the amount collected from BGE ratepayers for the nuclear decommissioning trust for Calvert Cliffs. We provide further details in the Cost for Decommissioning section.

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

In December 2006, the Maryland PSC issued an order that allows BGE to securitize its costs relating to the residential rate deferral through the issuance of bonds in an aggregate principal amount of approximately $630 million, subject to adjustment.

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

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

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

We discuss other aspects of Senate Bill 1 in Item 7. Management’s Discussion and Analysis—Business Environment—Senate Bill 1 section. We discuss 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 has implemented various programs for use when system-operating conditions or market economics indicate that a reduction in load would be beneficial. We refer to these programs as active load management programs. These programs include:

¨ two options for commercial and industrial customers to voluntarily reduce their electric loads,

¨ air conditioning control for residential and commercial customers, and

¨ residential water heater control.

These programs generally take effect on summer days when demand and/or wholesale prices are relatively high and had the capability during the 2006 summer to reduce load up to approximately 233 MW.

Transmission and Distribution Facilities

BGE maintains approximately 250 substations and 1,300 circuit miles of transmission lines throughout central Maryland. BGE also maintains approximately 23,900 circuit miles of distribution lines. The transmission facilities are connected to those of neighboring utility systems as part of PJM. Under the PJM Tariff and various agreements, BGE and other market participants can use regional transmission facilities for energy, capacity, and ancillary services transactions including emergency assistance.

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

Electric Operating Statistics

	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 includes network integration transmission service revenues, late payment charges, miscellaneous service fees, and tower leasing revenues.

Operating statistics do not reflect the elimination of intercompany transactions.

“Delivery service only” refers to BGE’s delivery of commodity that was purchased by the customer from an alternate supplier.

Gas Business

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

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

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

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, the Baltimore City Circuit Court upheld the rate order. However, certain parties have filed an appeal with the Court of Special Appeals. We cannot provide assurance that the Maryland PSC’s order will not be reversed in whole or in part or that certain issues will not be remanded to the Maryland PSC for reconsideration.

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

BGE purchases the natural gas it resells to customers directly from many producers and marketers. BGE has transportation and storage agreements that expire from 2007 to 2028.

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

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

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

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

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

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

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

Gas Operating 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 the elimination of intercompany transactions.

“Delivery service only” refers to BGE’s delivery of commodity that was purchased by the customer from an alternate supplier.

Franchises

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

Other Nonregulated Businesses

Energy Projects and Services

We offer energy projects and services designed primarily to provide energy solutions to large commercial and industrial and governmental customers. These energy products and services include:

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

¨ energy savings projects and performance contracting,

¨ energy consulting and procurement services ,

¨ services to enhance the reliability of individual electric supply systems, and

¨ customized financing alternatives.

Home Products and Gas Retail Marketing

We offer services to customers in Maryland including:

¨ home improvements,

¨ the service of heating, air conditioning, plumbing, electrical, and indoor air quality systems, and

¨ the sale of natural gas to residential customers.

Consolidated Capital Requirements

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

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

Environmental Matters

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

We continuously monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance. Our capital expenditures were approximately $100 million during the five-year period 2002-2006 to comply with existing environmental standards and regulations. Our estimated environmental capital requirements for the next three years are approximately $335 million in 2007, $495 million in 2008, and $305 million in 2009.

Air Quality

Federal

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

National Ambient Air Quality Standards (NAAQS)

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

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

In May 2005, the EPA adopted a stricter NAAQS for ozone and rescinded a requirement to impose fees on emissions sources in certain areas, including certain of our generating facilities, for failure to achieve the previous ozone standard. States will be required to submit plans to the EPA to meet the new standard by 2007, at which time the standard will take effect. We are unable to determine the impact that complying with the stricter NAAQS for ozone will have on our financial results until the states in which our generating facilities are located adopt plans to meet the new standard.

In December 2006, the United States Court of Appeals for the District of Columbia Circuit ruled that the requirement to impose fees on emissions sources based on the previous ozone standard remained applicable retroactive to November 2005 and remanded the issue to the EPA for reconsideration. At this time, we cannot predict what action the EPA will take in response to the Court’s decision and whether the fees will be retroactively assessed. The exact method of computing these fees has not been established and will depend in part on state implementation regulations that have not been finalized. Consequently, we are unable to estimate the ultimate financial impact of the fees in light of the uncertainty surrounding the methodology that

will be used in calculating the fees. However, any fees that are ultimately assessed could have a material adverse affect on our financial results.

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

Hazardous Air Emissions

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

New Source Review

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

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

In March 2006, the U.S. Court of Appeals for the District of Columbia annulled the equipment replacement rule adopted by the EPA in August 2003, which established a threshold for determining when major new source review requirements are triggered. We believe the Court decision, which was anticipated, should have minimal effect on us as it maintains the existing rules for equipment replacement. However, we anticipate that the EPA will continue to examine the existing equipment replacement rules and may again propose new rules. In addition, the U.S. Supreme Court has agreed to hear a case, not involving us, relating to the new source review requirements. We cannot predict the timing or outcome of any future EPA regulatory action or the outcome of the U.S. Supreme Court proceeding, or their possible effect on our financial results.

State

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

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

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

Capital Expenditure Estimates

We expect to incur additional environmental capital spending as a result of complying with the air quality laws and regulations discussed above. Based on the information currently available to us about CAIR, CAMR, HAA, and CPR, we will install additional air emission control equipment at our coal-fired generating facilities in Maryland and at our co-owned coal-fired facilities in Pennsylvania to meet air quality standards. We include in our estimated environmental capital requirements capital spending for these projects, which we expect will be approximately $320 million in 2007, $470 million in 2008, $290 million in 2009 and $40 million from 2010-2011.

Our estimates are subject to significant uncertainties including the timing of any additional federal and/or state regulations or legislation, the implementation timetables for such regulation or legislation, and the specific amount of emissions reductions that will be required at our facilities. As a result, we cannot predict our capital spending or the scope or timing of these projects with certainty, and the actual expenditures, scope and timing could differ significantly from our estimates. In addition, CAMR is subject to legal challenges filed by the states and industry and environmental groups. We cannot predict the timing or outcome of these challenges, or their possible effect on our financial results.

We believe that the additional air emission control equipment we plan to 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 compliance alternatives and their related costs, and although we cannot yet estimate the additional costs we may incur, such costs could be material.

Global Climate Change

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

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

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

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

Water Quality

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

Water Intake Regulations

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

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

Hazardous and Solid Waste

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

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

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

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

Employees

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

Item 1A. Risk Factors

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

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

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

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

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

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

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

Exposure to counterparty performance. Our merchant energy business enters into trades and hedging transactions with numerous third parties (commonly referred to as “counterparties”). In such arrangements, we are exposed to the credit risks of our counterparties and the risk that one or more counterparties may fail to perform their obligations to make payments or deliver fuel or power. These risks are enhanced during periods of commodity price fluctuations, such as is currently being experienced in the United States. Defaults by suppliers and other counterparties may adversely affect our financial results.

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

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

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

We are subject to extensive federal, state, and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife protection, the management of natural resources, and the protection of human health and safety that could, among other things, require additional pollution control equipment, limit the use of certain fuels, restrict the

output of certain facilities, or otherwise increase costs. Significant capital expenditures, operating and other costs are associated with compliance with environmental requirements, and these expenditures and costs could become even more significant in the future as a result of regulatory changes.

For example, 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 Maryland power generation facilities (including those owned and operated by us) than is required by current federal laws and regulations.

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

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

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

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

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

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

¨ mechanical or structural problems;

¨ inadequacy or lapses in maintenance protocols;

¨ impairment of reactor operation and safety systems due to human or mechanical error;

¨ costs of storage, handling and disposal of nuclear materials, including the availability or unavailability of a permanent repository for spent nuclear fuel;

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

¨ limitations on the amounts and types of insurance coverage commercially available;

¨ uncertainties regarding both technological and financial aspects of decommissioning nuclear generating facilities; and

¨ environmental risks, including risks associated with changes in environmental legal requirements.

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

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

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

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

We are an active participant in energy markets through our competitive energy businesses. The liquidity of regional energy markets is an important factor in our ability to manage risks in these operations. Over the past several years, several merchant energy businesses have ended or significantly reduced their activities as a result of several factors including government investigations, changes in market design and deteriorating credit quality. As a result, several regional energy markets experienced a significant decline in liquidity. While there have been recent improvements in liquidity, future reductions in liquidity may restrict our ability to manage our risks, and could impact our financial results.

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

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

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

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

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

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

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

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

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

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

If competitive restructuring of the electric and natural gas markets is reversed, discontinued, restricted or delayed, or if the recently enacted Maryland energy legislation is implemented or interpreted in a manner adverse to us, our business prospects and financial results could be negatively impacted.

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

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

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

Our merchant energy business has contractual obligations to certain customers to supply full requirements service to such customers to satisfy all or a portion of their energy requirements. The uncertainty regarding the amount of load that our merchant energy business must be prepared to supply to customers may

increase our operating costs. A significant under- or over-estimation of load requirements could result in our merchant energy business not having enough or having too much power to cover its load obligation, in which case it would be required to buy or sell power from or to third parties at prevailing market prices. Those prices may not be favorable and thus could increase our operating costs.

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

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

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

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

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

We rely on access to capital markets as a source of liquidity for capital requirements not satisfied by operating cash flows. If any of our credit ratings were to be downgraded, especially below investment grade, our ability to raise capital on favorable terms, including the commercial paper markets, could be hindered, and our borrowing costs would increase. Additionally, the business prospects of our wholesale and retail competitive supply businesses, which in many cases rely on the creditworthiness of Constellation Energy, would be negatively impacted. Some of the factors that affect credit ratings are cash flows, liquidity, and the amount of debt as a component of total capitalization.

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

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

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

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

Energy legislation enacted in Maryland in June 2006 mandates rate stabilization that requires BGE to defer the recovery of a portion of its purchased power costs and to phase in the recovery of these costs over a period of years. In addition, the legislation mandates that the Maryland PSC conduct a comprehensive review of Maryland’s deregulated electricity market. Because this energy legislation is still in the process of being implemented and interpreted, we do not know the final impact such legislation will have on our, or BGE’s, business.

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

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

Our qualified pension 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

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

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

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

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

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

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

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

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

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

Item 2. Properties

Constellation Energy’s corporate offices occupy approximately 106,000 square feet of leased office space in Baltimore, Maryland. The corporate offices for most of our merchant energy business occupy approximately 268,000 square feet of leased office space in another building in Baltimore, Maryland. We describe our electric generation properties on the next page. We also have leases for other offices and services located in the Baltimore metropolitan region, and for various real property and facilities relating to our generation projects.

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

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

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

¨ in public streets and highways pursuant to franchises, and

¨ on rights-of-way secured for the most part by grants from owners of the property.

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

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

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

The following table describes our generating facilities:

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) Reflects our proportionate interest in and entitlement to capacity from Keystone and Conemaugh, which include 2 MW of diesel capacity for Keystone and 1 MW of diesel capacity for Conemaugh.

The following table describes our processing facilities:

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 our legal proceedings in Note 12 to Consolidated Financial Statements.

Item 4. Submission of Matters to Vote of Security Holders

On December 8, 2006, we held our annual meeting of shareholders. At that meeting, the following matters were voted upon:

1. Class I Directors nominated by Constellation Energy were elected to serve for a term to expire in 2009 and until their successors are duly elected and qualified as follows:

	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 office continued 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. The ratification of PricewaterhouseCoopers LLP as independent registered public accounting 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 cast against was 1,846,861, and the number of abstentions was 1,437,743.

3. The shareholder proposal requesting Constellation Energy to declassify the Board of Directors was approved. With respect to holders of common stock, the number of affirmative votes cast was 76,259,034, the number of votes cast against was 7,688,559, the number of abstentions was 26,748,840, and the number of broker non-votes was 22,593,573.

Executive Officers of the Registrant

Name

Age

Present Office

Other Offices or Positions Held
During Past Five Years

Mayo A. Shattuck III

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

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

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

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

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

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

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.

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 are elected by, and hold office at the will of, the Board of Directors and do not serve a “term of office” as such. There is no arrangement or understanding between any director or officer and any other person pursuant to which the director or officer was selected.

PART II

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

Stock Trading

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

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

Dividend Policy

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

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

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

Quarterly dividends were declared on our common stock during 2006 and 2005 in the amounts set forth below.

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

¨ BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid; or

¨ any dividends (and any redemption payments) due on BGE’s preference stock have not been paid.

Common Stock Dividends and Price Ranges

	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 Sales of Equity Securities and Use of Proceeds

The following table presents shares surrendered by employees to exercise stock options and to satisfy tax withholding 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		—		—

Item 6. Selected Financial Data

Constellation Energy Group, 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