ML061710258

Annual Financial Reports of Constellation Energy and Long Island Power Authority

ML061710258
Person / Time
Site:	Nine Mile Point
Issue date:	06/12/2006
From:	Mark Miller Constellation Energy Group
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML061710258 (210)

Text

.Constellation Energy* P.O. Box 63 Lycoming, NY 13093 Nine Mile Point Nuclear Station June 12, 2006 U. S. Nuclear Regulatory Commission Washington, DC 20555-0001 ATTENTION: Document Control Desk

SUBJECT:

Nine Mile Point Nuclear Station Unit Nos. I and 2; Docket Nos. 50-220 and 50-410 2005 Annual Financial Reports of Constellation Energy and Long Island Power Authority Pursuant to 10 CFR 50.71(b), enclosed are copies of the 2005 Annual Financial Reports of Constellation Energy and Long Island Power Authority.

Should you have questions regarding the information in this submittal, please contact M. H. Miller, Licensing Director, at (315) 349-1510.

Very truly yours, a ý.Miller Licensing Director MHM/RF/sac Attachment (1) Annual Financial Report of Constellation Energy Group, Inc.

(2) Long Island Power Authority Basic Financial Statements cc: S.J. Collins, NRC T. G. Colburn, NRC Resident Inspector, NRC x>ADOYr-

Document Control Desk June 12, 2006 Page 2 bcc: L. S. Larragoite C. W. Fleming, Esquire T. J. O'Connor J. A. Hutton M. H. Miller/T. F. Syrell J. L. Lyon NMPIL 2050 ICOMMITMENTS IDENTIFIED IN THIS CORRESPONDENCE:

0 NONE Posting Requirements for Responses - NOV/Order No

ATTACHMENT (1)

Annual Financial Report of Constellation Energy Group, Inc.

Nine Mile Point Nuclear Station, LLC June 2, 2006

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, 2005 Commission IRS Employer file number Exact name of registrant as specified in its charter 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. PRATF 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:

Name of each exchange on Title of each dass which registered New York Stock Exchange, Inc.

Constellation Energy Group, Inc. Common Stock-Without Par Value Chicago Stock Exchange, Inc.

Pacific 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 Nw York Stock Exchange Inc.

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACI:

Not Applicable Indicate by check mask if Constellation Energy Group, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes 0 No 0.

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 0 No l.

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 El No 0.

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 El No E0.

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 0 No El.

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. 0 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 g Accelerated filer [E Non-accelerated filer El 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 El Accelerated filer El Non-accelerated filer 0 Indicate by check mark whether Constellation Energy Group, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes D No[]

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 0 No M Aggregate market value of Constellation Energy Group, Inc. Common Stock, without par value, held by non-affiliates as of June 30, 2005 was approximately $10,225,051,449 based upon New York Stock Exchange composite transaction closing price.

CONSTELLATION ENERGY GROUP, INC. COMMON STOCK WITHOUT PAR VALUE 178,454,929 SHARES OUTSTANDING ON JANUARY 31, 2006.

DOCUMENTS INCORPORATED BY REFERENCE Part of Form 10-K Document Incorporated by Reference III Certain sections of the Proxy Statement for the 2006 Annual Meeting of Shareholders for Constellation Energy Group, Inc.

Baltimore Gas and Electric Company meets the conditions set forth in General Instruction I(l)(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 I - Business ........................................................................... 2 O verview ...................................................................... 2 M erchant Energy Business ....................................................... 3 Baltimore Gas and Electric Company .............................................. 10 Other Nonregulated Businesses ................................................... 15 Consolidated Capital Requirements ................................................ 15 Environmental M atters .......................................................... 15 Employees ..................................................................... 18 Item 1A - Risk Factors ........................................................................ 19 Item 2 - Properties .......................................................................... 25 Item 3 - Legal Proceedings ................................................................... 27 Item 4 - Submission of Matters to Vote of Security Holders ....................................... 27 Executive Officers of the Registrant (Instruction 3 to Item 401((b) of Regulation S-K) ......... 27 PART II Item 5 - Market for Registrants Common Equity and Related Shareholder Matters ................... 29 Item 6 - Selected Financial Data .............................................................. 30 Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations ...... 32 Item 7A - Quantitative and Qualitative Disclosures About Market Risk ............................... 67 Item 8 - Financial Statements and Supplementary Data ........................................... 68 Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ...... 125 Item 9A - Controls and Procedures ............................................................. 125 Item 9B - Other Information .................................................................. 125 PART III Item 10 - Directors and Executive Officers of the Registrant ........................................ 126 Item 11 - Executive Compensation ............................................................. 126 Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters 126 Item 13 - Certain Relationships and Related Transactions .......................................... 127 Item 14 - Principal Accountant Fees and Services ................................................. 127 PART IV Item 15 - Exhibits and Financial Statement Schedules ............................................. 128 Signatures ..................................................................................... 134

Forward Looking Statements

• the effectiveness of Constellation Energy's and We make statements in this report that are considered BGE's risk management policies and procedures forward looking statements within the meaning of the and the ability and willingness of our Securities Exchange Act of 1934. Sometimes these counterparties to satisfy their financial and statements will contain words such as "believes," performance commitments, "anticipates," "expects," "intends," "plans," and other " operational factors affecting commercial similar words. We also disclose non-historical operations of our generating facilities (including information that represents management's expectations, nuclear facilities) and BGE's transmission and which are based on numerous assumptions. These distribution facilities, including catastrophic statements and projections are not guarantees of our weather-related damages, unscheduled outages future performance and are subject to risks, or repairs, unanticipated changes in fuel costs uncertainties, and other important factors that could or availability, unavailability of coal or gas cause our actual performance or achievements to be transportation or electric transmission services, materially different from those we project. These risks, workforce issues, terrorism, liabilities associated uncertainties, and factors include, but are not with catastrophic events, and other events limited to: beyond our control,

" the timing and extent of changes in commodity " the actual outcome of uncertainties associated prices and volatilities for energy and energy with assumptions and estimates using judgment related products including coal, natural gas, oil, when applying critical accounting policies and electricity, nuclear fuel, and emission preparing financial statements, including factors allowances, that are estimated in determining the fair value

" the liquidity and competitiveness of wholesale of energy contracts, such as the ability to markets for energy commodities, obtain market prices and, in the absence of

• the effect of weather and general economic and verifiable market prices, the appropriateness of business conditions on energy supply, demand, models and model inputs (including, but not and prices, limited to, estimated contractual load

" the ability to attract and retain customers in obligations, unit availability, forward our competitive supply activities and to commodity prices, interest rates, correlation and adequately forecast their energy usage, volatility factors),

" the timing and extent of deregulation of, and

• changes in accounting principles or practices, competition in, the energy markets, and the " losses on the sale or write down of assets due rules and regulations adopted in those markets, to impairment events or changes in

" uncertainties associated with estimating natural management intent with regard to either gas reserves, developing properties, and holding or selling certain assets, extracting natural gas, " cost and other effects of legal and

" regulatory or legislative developments that affect administrative proceedings that may not be deregulation, the price of energy, transmission covered by insurance, including environmental or distribution rates and revenues, demand for liabilities, and energy, or increases in costs, including costs " the likelihood and timing of the completion of related to nuclear power plants, safety, or the pending merger with FPL Group, Inc. (FPL environmental compliance, Group), the terms and conditions of any

• the inability of Baltimore Gas and Electric required regulatory approvals of the pending Company (BGE) to recover all its costs merger, and potential diversion of associated with providing electric residential management's time and attention from our customers service during or after the electric ongoing business during this time period.

rate freeze period, Given these uncertainties, you should not place

+ the conditions of the capital markets, interest undue reliance on these forward looking statements.

rates, foreign exchange rates, availability of Please see the other sections of this report, including credit facilities to support business Item 1A. Risk Factors, and our other periodic reports requirements, and general economic conditions, filed with the Securities and Exchange Commission as well as Constellation Energy Group's (SEC) for more information on these factors. These (Constellation Energy) and BGE's ability to forward looking statements represent our estimates and maintain their current credit ratings, 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.

1

PART I " an electric and natural gas retail operation that htem 1. Business provides energy products and services to commercial, industrial, and governmental Pending Merger with FPL Group, Inc.

customers, and On December 18, 2005, Constellation Energy entered

" a generation operations and maintenance into an Agreement and Plan of Merger with FPL services operation.

Group. The merger agreement has been unanimously BGE is a regulated electric transmission and approved by both companies' boards of directors but distribution utility company and a regulated gas completion of the merger is contingent upon, among distribution utility company with a service territory that other things, the approval of the transaction by covers the City of Baltimore and all or part of ten shareholders of both companies and receipt of required counties in central Maryland. BGE was incorporated in regulatory approvals. The companies anticipate Maryland in 1906.

obtaining all necessary approvals and completing the Our other nonregulated businesses:

merger by the end of 2006. The merger agreement

• design, construct, and operate heating, cooling, contains certain termination rights for both and cogeneration facilities for commercial, Constellation Energy and FPL Group, and further industrial, and governmental customers provides for the payment of fees upon termination of throughout North America, and the merger agreement under specified circumstances.

• provide home improvements, service heating, Further information concerning the pending merger will air conditioning, plumbing, electrical, and be included in the joint proxy statement/prospectus indoor air quality systems, and provide natural contained in the registration statement on Form S-4 to gas to residential customers in central be filed by Constellation Energy in connection with the Maryland.

merger. For additional information related to the For a discussion of recent events that have merger, see Note 15 to the Consolidated Financial impacted us, our strategy, and the seasonality of our Statements.

business, please refer to Item Z Management! Discussion andAnalysis section.

Overview Constellation Energy maintains a website at Constellation Energy is an energy company which constellation.com where copies of our annual reports on includes a merchant energy business and BGE, a Form 10-K, quarterly reports on Form 10-Q, current regulated electric and gas public utility in central reports on Form 8-K, and any amendments may be Maryland. obtained free of charge. These reports are posted on our Constellation Energy was incorporated in website the same day they are filed with the SEC. The Maryland on September 25, 1995. On April 30, 1999, SEC maintains a website (sec.gov), where copies of our Constellation Energy became the holding company for filings may be obtained free of charge. The website BGE and its subsidiaries. References in this report to address for BGE is bge.com. These website addresses are "we" and "our" are to Constellation Energy and its inactive textual references, and the contents of these subsidiaries, collectively. References in this report to the websites are not part of this Form 10-K.

"regulated business(es)" are to BGE. In addition, the website for Constellation Energy Our merchant energy business is a competitive includes copies of our Corporate Governance provider of energy solutions for a variety of customers.

Guidelines, Principles of Business Integrity, Corporate It has electric generation assets located in various Compliance Program and Insider Trading Policy, and regions of the United States and provides energy the charters for the Audit, Compensation and solutions to meet customers' needs. Our merchant Nominating, and Corporate Governance Committees of energy business focuses on serving the full energy and the Board of Directors. Copies of each of these capacity requirements (load-serving) of, and providing documents may be printed from the website or may be other energy products and risk management services for obtained from Constellation Energy upon written various customers. request to the Corporate Secretary.

Our merchant energy business includes: The Principles of Business Integrity is a code of

" a generation operation that owns, operates, and ethics which applies to all of our directors, officers, and maintains fossil, nuclear, and hydroelectric employees, including the chief executive officer, chief generating facilities and holds interests in financial officer, and chief accounting officer. We will qualifying facilities, fuel processing facilities and post any amendments to, or waivers from, the power projects in the United States, Principles of Business Integrity applicable to our chief

" a wholesale marketing and risk management executive officer, chief financial officer, or chief operation that primarily provides energy accounting officer on our website.

products and services to distribution utilities, power generators, and other wholesale customers, 2

Operating Segments Constellation Generation Group, our merchant The percentages of revenues, net income, and assets generation operation, oversees the ownership, attributable to our operating segments are shown in the operations, maintenance, and performance of our fossil, tables below. We present information about our nuclear and renewable generation and fuel processing operating segments, including certain other items, in facilities. Our generation capacity supports our Note 3 to the ConsolidatedFinancialStatements. wholesale and retail operations by providing a source of Unaffiliated Revenues reliable power supply. Constellation Generation Group Merchant Regulated Regulated Other also owns and operates a generation operations and Energy Electric Gas Nonregulated maintenance services organization.

Our merchant energy business:

2005 81% 12% 6% 1% " provided service to distribution utilities, 2004 76 16 6 2 municipalities, commercial and industrial, and 2003 68 20 8 4 governmental customers with approximately Net Income (1) 39,500 megawatts (MW) of peak load in the Merchant Reglated Regulated Other aggregate during 2005, Energy Eectric Gas Nonregulated " provided approximately 300,000 million British 2005 71% 25% 4% -0,0 Thermal Units (mmBTUs) of natural gas to 2004 75 23 4 (2) commercial, industrial, and governmental 2003 66 24 9 1 customers during 2005, Total Assets

" delivered 12.6 million tons of coal to international and domestic third-party Merchant Regulated Regulated Other Energy Electric Gas Nonregulated customers and to our own fleet during 2005, and 2005 77% 16% 6% 1% " managed approximately 11,850 MW of 2004 71 20 7 2 generation capacity.

2003 67 23 7 3 We analyze the results of our merchant energy Certainprior-yearamounts have been reclasified to business as follows:

conform with the current year'spresentation. " Mid-Atlantic Region-our fossil, nuclear, and (1) Excludes income (loss) on discontinued operations hydroelectric generating facilities and in 2005, 2004, and 2003 and cumulative effects of load-serving activities in the PJM changes in accounting principles in 2005 and 2003 Interconnection (PJM) region. This also as discussed in more detail in Item 8. Financial includes active portfolio management of the Statements and Supplementary Data. generating assets and other physical and financial contractual arrangements, as well as other PJM competitive supply activities.

Merchant Energy Business Introduction

• Plants with Power Purchase Agreements-our Our merchant energy business integrates electric generating facilities outside the Mid-Atlantic generation assets with the marketing and risk Region with long-term power purchase management of energy and energy-related commodities, agreements, including our Nine Mile Point allowing us to manage energy price risk over geographic Nuclear Station (Nine Mile Point), R.E. Ginna regions and time. Nuclear Plant (Ginna), University Park, and Constellation Energy Commodities Group, our High Desert generating facilities.

wholesale marketing and risk management operation,

• Wholesale Competitive Supply--our marketing dispatches the energy from our generating facilities and and risk management operation that provides from some facilities with which we have power purchase energy products and services (including agreements, manages the risks associated with selling the portfolio management and trading activities) output and purchasing non-nuclear fuels, and enters outside the Mid-Atlantic Region primarily to into transactions to meet customers' energy and risk distribution utilities, power generators, and management requirements. This operation also trades other wholesale customers. We also provide energy and energy-related commodities and deploys risk global coal and upstream and downstream capital in the management of our portfolio in order to' natural gas services.

earn additional returns. Constellation NewEnergy, our " Retail Competitive Supply-our operation that electric and gas retail operation, provides electricity, provides electric and natural gas energy natural gas, transportation, and other energy services to products and services to commercial, industrial commercial, industrial, and governmental customers. and governmental customers.

" Other-our investments in qualifying facilities and domestic power projects and our generation operations and maintenance services.

3

We present details about our generating properties After termination of the power purchase in Item 2. Properties. agreements, a revenue sharing agreement with the former owners of the plant will begin and continue Mid-Atlantic Region through 2021. Under this agreement, which applies We own 6,960 MW of fossil, nuclear, and hydroelectric only to our ownership percentage of Unit 2, a generation capacity in the Mid-Atlantic Region. The predetermined price is compared to the market price for output of these plants is managed by our wholesale electricity. If the market price exceeds the strike price, marketing and risk management operation and is then 80% of this excess amount is shared with the hedged through a combination of power sales to former owners of the plant. The revenue sharing wholesale and retail market participants. Our merchant agreement is unit contingent and is based on the energy business meets the load-serving requirements of operation of the unit.

various contracts using the output from the We exclusively operate Unit 2 under an operating Mid-Atlantic Region and from purchases in the agreement with the Long Island Power Authority. The wholesale market. Long Island Power Authority is responsible for 18% of BGE transferred all of these facilities to our the operating costs (and decommissioning costs) of Unit merchant energy generation subsidiaries on July 1, 2000 2 and has representation on the Nine Mile Point Unit 2 as a result of the implementation of electric customer management committee which provides certain choice and competition among suppliers in Maryland, oversight and review functions.

except for the Handsome Lake, Big Sandy, and Wolf In May 2004, we filed an application with the Hills facilities that commenced operations in mid-2001. Nuclear Regulatory Commission (NRC) for a 20-year The assets transferred from BGE are subject to the lien license extension for both units at Nine Mile Point.

of BGE's mortgage. The license to operate Nine Mile Point's Unit 1 expires Our merchant energy business provides power to in 2009 and the license to operate Unit 2 expires in enable BGE to provide standard offer service as 2026. We must demonstrate that we can ensure that discussed in the Baltimore Gas and Electric Company- the units will continue to perform their intended Standard Offer Service section. For 2005, the peak load functions through the renewal period. The NRC will supplied to BGE was approximately 4,000 MW. also consider the impact of the 20-year license extension on the environment. We expect to receive approval of Plants with Power Purchase Agreements our application by early 2007 and have assumed a We own 3,189 MW of nuclear and natural gas 20-year license extension for purposes of recording generation capacity with power purchase agreements for depreciation expense and asset retirement obligations.

their output. Our facilities with power purchase However, we cannot predict the actual timing of the agreements consist of. NRC's decision, or the impact of the decision, if any,

" the Nine Mile Point facility, on our financial results. If we do not receive the license

" the Ginna facility, extension, we will not be able to operate the Nine Mile

" the High Desert facility, and Point units beyond 2009 and 2026.

" the University Park facility. In June 2004, we purchased the Ginna nuclear We own 100% of Nine Mile Point Unit 1 (620 facility which is located in Ontario, New York from MW) and 82% of Unit 2 (941 MW). The remaining Rochester Gas & Electric Corporation (RG&E). Ginna interest in Nine Mile Point Unit 2 is owned by the consists of a 498 MW reactor that entered service in Long Island Power Authority. Unit 1 entered service in 1970 and is licensed to operate until 2029. The 1969 and Unit 2 in 1988. Nine Mile Point is located acquisition includes a long-term unit contingent power within the New York Independent System Operator purchase agreement under which we sell up to 90% of (NYISO) region. the plant's output and capacity to RG&E for 10 years We sell 90% of our share of Nine Mile Point's at an average price of $44.00 per MWH. The output to the former owners of the plant at an average remaining output is managed by our wholesale price of nearly $35 per megawatt-hour (MWH) under marketing and risk management operation and sold into agreements that terminate between 2009 and 2011. The the wholesale market. We expect to increase the agreements are unit contingent (if the output is not capacity of Ginna by 83 MW through a planned uprate available because the plant is not operating, there is no in 2006.

requirement to provide output from other sources). The remaining 10% of Nine Mile Point's output is managed by our wholesale marketing and risk management operation and sold into the wholesale market.

4

The High Desert facility has a long-term power

• unit contingent purchases from generation sales agreement with the California Department of companies, Water Resources (CDWR). The agreement has a " our generation assets, "tolling" feature, under which the CDWR pays a fixed " regional power pools, and amount of $12.1 million per month which provides " tolling contracts with generation companies, CDWR the right, but not the obligation, to purchase which provide us the right, but not the power at a price linked to the variable cost of obligation, to purchase power at a price linked production. During the term of the agreement, which to the variable cost of production, including runs until January 2011, the facility will provide energy fuiel, with terms that generally extend from exclusively to the CDWR. several months to several years but can be We have sold 100% of the output of the longer.

University Park facility under a tolling agreement ending May 31, 2006. Under this tolling agreement, Portfolio Management and Trading our counterparty will pay a fixed amount per month Our wholesale marketing and risk management and have the right, but not the obligation, to purchase operation actively uses energy and energy-related power from us at prices linked to the variable fuel and commodities in order to manage our portfolio of energy other costs of production. purchases and sales to customers through structured In the second quarter of 2005, we sold our transactions. As part of our risk management activities, Oleander generating facility. We discuss this sale in we trade energy and energy-related commodities and more detail in Note 2 to the ConsolidatedFinancial deploy risk capital in the management of our portfolio Statements. in order to earn additional returns. These activities are managed through daily value at risk and stop loss limits Competitive Supply and liquidity guidelines, and could have a material We are a leading supplier of energy products and impact on our financial results. We discuss the impact services to wholesale customers and retail commercial of our trading activities and value at risk in more detail and industrial customers. In 2005, our wholesale in Item 7. Management's Discmssion and Analysis.

marketing and risk management operation provided These activities involve the use of a variety of approximately 24,000 peak MWs of wholesale full instruments, including:

requirements load-serving products. During 2005, our

• forward contracts (which commit us to retail competitive supply activities served approximately purchase or sell energy commodities in the 15,500 MW of peak load and approximately 300,000 future),

mmBTUs of natural gas. Our competitive supply " swap agreements (which require payments to or activities also include 1,465 MWýV of capacity from our from counterparties based upon the difference Rio Nogales and Holland Energy natural gas-fired between two prices for a predetermined generating facilities. These facilities are not sold forward contractual (notional) quantity),

under long-term agreements, and their output is used to " option contracts (which convey the right to buy serve customer requirements. or sell a commodity, financial instrument, or index at a predetermined price), and Wholesale and Retail Load-ServingActivities

" futures contracts (which are exchange traded We structure transactions that serve the full energy and standardized commitments to purchase or sell a capacity requirements of various customers outside the commodity or financial instrument, or make a PJM region such as distribution utilities, municipalities, cash settlement, at a specified price and future cooperatives, and retail aggregators that do not own date).

sufficient generating capacity or in-house supply Active portfolio management allows our wholesale functions to meet their own load requirements. We also marketing and risk management operation to:

structure transactions to supply full energy and capacity

" manage and hedge its fixed-price energy requirements and provide natural gas, transportation, purchase and sale commitments, and other energy products and services to retail

" provide fixed-price energy commitments to commercial and industrial customers.

customers and suppliers, Contracts with these customers generally extend

• reduce exposure to the volatility of market from one to ten years, but some can be longer. To meet prices, and our customers' load-serving requirements, our merchant

" hedge fuel requirements at our non-nuclear energy business obtains energy from various sources, generation facilities.

including:

• bilateral power purchase agreements with third parties, 5

Coal Services Fuel Sources Our wholesale marketing and risk management Our power plants use diverse fuel sources. Our fuel mix operation participates in global coal sourcing activities based on capacity owned at December 31, 2005 and by providing coal and coal related logistical services, our generation based on actual output by fuel type in such as transportation for the variable or fixed supply 2005 were as follows:

needs of North American and international power generators. In 2005, we delivered 12.6 million tons of Fuel Capacity Owned Generation coal to international and domestic third-party customers Nuclear .............. 32% 52%

and to our own fleet. Coal ................. 23 30 We also include in our coal services the results Natural Gas ........... 31 14 from our synthetic fuel processing facility in South Oil .................. 6 1 Carolina. Renewable and Alternative (1) ...... 4 2 Natural Gas Services Dual (2) .............. 4 1 Our wholesale marketing and risk management (1) Includes solar, geothermal, hydro, and biomass.

operation provides products and services to upstream (2) Switches between natural gas and oil.

(exploration and production) and downstream (transportation and storage) natural gas customers, We discuss our risks associated with fuel in more including large utilities, industrial customers, power detail in Item 7. Management'r Discussion and Analysis-generators, wholesale marketers, and retail aggregators.

Marker Risk.

In June 2005, we acquired working interests in gas producing fields in Texas and Alabama. We discuss this asset acquisition in more detail in Note 15 to the Nuclear ConsolidatedFinancialStatements. The output at our nuclear facilities over the past five years (including periods prior to our acquisition of Nine Other Mile Point and Ginna) is presented in the following We hold up to a 50% voting interest in 24 operating table:

energy projects that consist of electric generation Calvert Cliffs Nine Mile Point Ginna (primarily relying on alternative fuel sources), fuel Capacity Capacity Capacity processing, or fuel handling facilities and are qualifying MWII Factor MWHI* Factor MWH Factor facilities under the Public Utility Regulatory Policies Act (MWH in millions) of 1978. Each electric generating plant sells its output 2005 14.7 97% 12.7 93% 4.0 93%

to a local utility under long-term contracts. 2004 14.5 96 12.1 89 4.3 100 We also provide operation and maintenance 2003 13.7 93 12.2 90 3.9 90 services, including testing and start-up, to owners of 2002 12.1 82 11.7 87 3.8 89 electric generating facilities. 2001 13.6 92 11.6 86 4.3 100

• represents our proportionate ownership interest Unistar Nuclear The supply of fuel for nuclear generating stations In 2005, we formed a joint enterprise with includes the:

AREVA, Inc., to develop a standardized fleet of nuclear

" purchase of uranium (concentrates and uranium power plants based on an advanced design called the hexafluoride),

U.S. Evolutionary Power Reactor (U.S. EPR). We

" conversion of uranium concentrates to uranium intend to work with AREVA, Inc. to obtain design hexafluoride, certification and all necessary approvals from the NRC

" enrichment of uranium hexafluoride, and to license, construct, own, and operate U.S. EPR plants.

" fabrication of nuclear fuel assemblies.

Unistar Nuclear will offer the business framework that could enable the development of future joint ventures Uranium and We have commitments for sufficient with Constellation Energy, other energy companies, and Conversion quantities of uranium (concentrates and interested parties. Those future joint ventures, in turn, uranium hexafluoride) to meet 100% of would license, construct, own, and operate nuclear our total requirements through 2008.

power plants as part of a standardized fleet. However, Additionally, we have commitments prior to identifying specific Projects or committing to covering approximately 80% of our ordering new nuclear power plants, our financial requirements in 2009 and 85% in 2010.

commitment will be limited to the formation of the Enrichment We have commitments that provide business platform and business development activities, 100% of our uranium enrichment including early-stage licensing and permit activities. requirements through 2010 and 25% of these requirements in 2011 and 2012.

6

Fuel Assembly We have commitments for the fabrication Storage of Spent Nuclear Fuel-On-Site Facilities Fabrication of fuel assemblies for reloads required Calvert Cliffs has a license from the NRC to operate an through 2013 for Nine Mile Point and on-site independent spent fuel storage installation that Calvert Cliffs Nuclear Power Plant, Inc. expires in 2012. We have storage capacity at Calvert (Calvert Cliffs), and through 2017 for Cliffs that will accommodate spent fuel from operations Ginna. through 2008. In addition, we can expand our The nuclear fuel markets are competitive, and temporary storage capacity at Calvert Cliffs to meet although prices for uranium and conversion are future requirements until approximately 2025.

increasing, we do not anticipate any significant Currently, Nine Mile Point and Ginna do not have problems in meeting our future requirements. independent spent fuel storage capacity. Rather, Nine Mile Point's Unit I and Ginna have sufficient storage Storage of Spent Nuclear Fuel-FederalFacilities capacity within the plants until 2010. Nine Mile Point's One of the issues associated with the operation and Unit 2 has sufficient storage capacity within the plant decommissioning of nuclear generating facilities is until 2012. After that time, independent spent fuel disposal of spent nuclear fuel. There are no facilities for storage capability may need to be developed at each the reprocessing or permanent disposal of spent nuclear site.

fuel currently in operation in the United States, and the NRC has not licensed any such facilities. The Nuclear Costfor Decommissioning Uranium EnrichmentFacilities Waste Policy Act of 1982 (NWPA) required the federal The Energy Policy Act of 1992 requires domestic government, through the Department of Energy nuclear utilities to contribute to a fund for (DOE), to develop a repository for the disposal of spent decommissioning and decontaminating uranium nuclear fuel and high-level radioactive waste. enrichment facilities that had been operated by DOE.

As required by the NWPA, we are a party to These contributions are generally payable over a 15-year contracts with the DOE to provide for disposal of spent period with escalation for inflation and are based upon nuclear fuel from our nuclear generating plants. The the amount of uranium enriched by DOE for each NWPA and our contracts with the DOE require utility through 1992. The 1992 Act provides that these payments to the DOE of one tenth of one cent (one costs are recoverable through utility service rates. BGE mill) per kilowatt hour on nuclear electricity generated is solely responsible for these costs as they relate to and sold to pay for the cost of long-term nuclear fuel Calvert Cliffs and will make the last payment in 2006.

storage and disposal. We continue to pay those fees into The sellers of the Nine Mile Point plant and the Long the DOE's Nuclear Waste Fund for Calvert Cliffs, Island Power Authority are responsible for the costs Ginna, and Nine Mile Point. The NWPA and our relating to the Nine Mile Point plant. The seller of contracts with the DOE required the DOE to begin Ginna is responsible for the costs related to that facility.

taking possession of spent nuclear fuel generated by Cost for Decommissionini nuclear generating units no later than January 31, 1998. We are obligated to decommission our nuclear plants at The DOE has stated that it will not meet that the time these plants cease operation. Every two years, obligation until 2010 at the earliest. This delay has the NRC requires us to demonstrate reasonable required that we undertake additional actions to provide assurance that funds will be available to decommission on-site fuel storage at Calvert Cliffs, Ginna, and Nine the sites. When BGE transferred all of its nuclear Mile Point, including the installation of on-site dry fuel generating assets to our merchant energy business, it storage capacity at Calvert Cliffs, as described in more also transferred the trust fund established to pay for detail below. In 2004, complaints were filed against the decommissioning Calvert Cliffs. At December 31, 2005, federal government in the United States Court of the trust fund assets were $370.4 million.

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 RG&E's rights and obligations related to recovery of damages from the DOE were assigned to us. However, we have an obligation to reimburse RG&E for up to the first $10 million of any recovered damages.

7

Under the Maryland Public Service Commission's Coal (Maryland PSC) order regarding the deregulation of We purchase the majority of our coal for electric electric generation, BGE ratepayers must pay a total of generation under supply contracts with mining

$520 million, in 1993 dollars adjusted for inflation, to operators, and we acquire the remainder in the spot or decommission Calvert Cliffs through fixed annual forward coal markets. We believe that we will be able to collections of approximately $18.7 million until renew supply contracts as they expire or enter into June 30, 2006, and thereafter in an annual amount contracts with other coal suppliers. Our primary coal determined by reference to specified factors. We are burning facilities have the following requirements:

required to submit a filing to the Maryland PSC by Approximate April 2006 to determine the annual amount BGE Annual Coal ratepayers will pay, if any, for decommissioning Calvert Requirement Special Coal (tons) Restrictions Cliffs after June 30, 2006. BGE is collecting this amount on behalf of Calvert Cliffs. Any costs to Brandon Shores 3,500,000 Sulfur content less decommission Calvert Cliffs in excess of this Units 1 and 2 than 1.20 lbs per

$520 million must be paid by Calvert Cliffs. If BGE (combined) mmBTU ratepayers have paid more than this amount at the time C. P. Crane 850,000 Low ash melting of decommissioning, Calvert Cliffs must refund the Units 1 and 2 temperature excess. If the cost to decommission Calvert Cliffs is less (combined) than the $520 million BGE's ratepayers are obligated to H. A. Wagner 1,100,000 Sulfur content no pay, Calvert Cliffs may keep the difference. Units 2 and 3 more than 1%

The sellers of Nine Mile Point transferred a (combined)

$441.7 million decommissioning trust fund to us at the Coal deliveries to these facilities are made by rail time of sale. In return, we assumed all liability for the and barge. We primarily use coal produced from mines costs to decommission Unit 1 and 82% of the costs to located in central and northern Appalachia. The timely decommission Unit 2. We believe that this amount is delivery of coal together with the maintenance of adequate to cover our responsibility for appropriate levels of inventory is necessary to allow for decommissioning Nine Mile Point to a greenfield status continued, reliable generation from these facilities.

(restoration of the site so that it substantially matches During 2003, we expanded our coal sources the natural state of the surrounding properties and the including restructuring our rail contracts, increasing the site's intended use). At December 31, 2005, the Nine range of coals we can consume, adding synthetic fuel as Mile Point trust fund assets were $518.3 million. an alternate source, and finding potential other coal The seller of Ginna transferred $200.8 million in supply sources including shipments from Columbia, decommissioning funds to us. In return, we assumed all Venezuela, South Africa, and other international sources.

liability for the costs to decommission the unit. We All of the Conemaugh and Keystone plants' annual believe that this amount will be sufficient to cover our coal requirements are purchased by the plant operators responsibility for decommissioning Ginna to a from regional suppliers on the open market. The sulfur greenfield status. At December 31, 2005, the Ginna restrictions on coal are approximately 2.3% for the trust fund assets were $222.0 million. 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.

8

Gas With respect to power generation, we compete in We purchase natural gas, storage capacity, and the operation of energy-producing projects, and our transportation, as necessary, for electric generation at competitors in this business are both domestic and certain plants. Some of our gas-fired units can use international organizations, including various utilities, residual fuel oil or distillates instead of gas. Gas is industrial companies and independent power producers purchased under contracts with suppliers on the spot (including affiliates of utilities, financial investors, banks market and forward markets, including financial and investment banks), some of which have financial exchanges and bilateral agreements. The actual fuel resources that are greater than ours.

quantities required can vary substantially from year to States are considering different types of regulatory year depending upon the relationship between energy initiatives concerning competition in the power prices and fuel costs, weather conditions, and operating industry, which makes a competitive assessment requirements. However, we believe that we will be able difficult. Increased competition that resulted from some to obtain adequate quantities of gas to meet our of these initiatives in several states contributed in some requirements. instances to a reduction in electricity prices and put pressure on electric utilities to lower their costs, Oil including the cost of purchased electricity. While many Under normal bum practices, our requirements for states continue to support retail competition and residual fuel oil (No. 6) amount to approximately industry restructuring, other states that were considering 1.5 million to 2.0 million barrels of low-sulfur oil per deregulation have slowed their plans or postponed year. Deliveries of residual fuel oil are made from the consideration of deregulation. In addition, other states suppliers' Baltimore Harbor and Philadelphia marine are reconsidering deregulation.

terminals for distribution to the various generating plant We believe there is adequate growth potential in locations. Also, based on normal burn practices, we the current deregulated market and that further market require approximately 8.0 million to 11.0 million changes could provide additional opportunities for our gallons of distillates (No. 2 oil and kerosene) annually, merchant energy business. Our wholesale marketing and but these requirements can vary substantially from year risk management operation also participates in global to year depending upon the relationship between energy coal sourcing activities by providing coal for the variable prices and fuel costs, weather conditions, and operating or fixed supply needs of North American and requirements. Distillates are purchased from the international power generators. In addition, our suppliers' Baltimore truck terminals for distribution to wholesale marketing and risk management operation the various generating plant locations. We have provides products and services to upstream and contracts with various suppliers to purchase oil at spot downstream natural gas customers.

prices, and for future delivery, to meet our As the market for commercial and industrial requirements. supply continues to grow, we have experienced increased competition on a regional basis in our retail commercial Competition and industrial supply activities. The increase in retail Market developments over the past several years have competition and the impact of wholesale power prices changed the nature of competition in the merchant compared to the rates charged by local utilities has, in energy business. Certain companies within the merchant certain circumstances, reduced the margins that we energy sector have curtailed their activities or withdrawn realize from our customers. However, we believe that completely from the business. However, new our experience and expertise in assessing and managing competitors (e.g., financial investors, banks and risk and our strong focus on customer service will help investment banks) have entered the market. We us to remain competitive during volatile or otherwise encounter competition from companies of various sizes, adverse market circumstances.

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 or transportation. We principally compete on the basis of price, customer service, reliability, and availability of our products.

9

Merchant Energy Operating Statistics 2005 2004 2003 2002 2001 Revenues (In millions)

Mid-Atlantic Region $ 2,283.9 $ 1,925.6 $1,696.2 $1,415.1 $1,379.2 Plants with Power Purchase Agreements 829.6 714.5 574.6 433.2 70.8 Competitive Supply-Retail 6,942.3 4,280.0 2,567.7 312.7 -

Competitive Supply-Wholesale 4,672.3 3,353.8 2,703.9 540.7 233.5 Other 58.0 73.6 45.1 56.4 80.5 Total Revenues $14,786.1 $10,347.5 $7,587.5 $2,758.1 $1,764.0 Generation (In millions)--MWH 60.2 55.3 51.6 44.7 37.4 Operating statistics do not reflect the elimination ofintercompany transactions.

Certainprior-yearamounts have been reclassifiedto conform with the current yearspresentation.

Baltimore Gas and Electric Company " Commercial and industrial customers have BGE is an electric transmission and distribution utility several service options that fix competitive company and a gas distribution utility company with a transition charges (CTC) through June 30, service territory that covers the City of Baltimore and 2006, at which time the CTC will be all or part of ten counties in central Maryland. BGE is phased-out. CTC revenues were provided to regulated by the Maryland PSC and Federal Energy allow BGE to recover stranded costs that Regulatory Commission (FERC) with respect to rates resulted from the deregulation of BGE's and other aspects of its business. generating assets.

BGE's electric service territory includes an area of

• BGE residential base rates for delivery service approximately 2,300 square miles. There are no will not change before July 2006. Total municipal or cooperative wholesale customers within residential base rates remain unchanged over BGE's service territory. BGE's gas service territory the initial transition period (July 1, 2000 includes an area of approximately 800 square miles. through June 30, 2006), as annual standard BGE's electric and gas revenues come from many offer service rate increases are offset by customers-residential, commercial, and industrial. corresponding decreases in the CTC that BGE receives from its customers.

Electric Business

• While BGE does not sell electric commodity to Electric Regulatory Mlatters and Competition all customers in its service territory, BGE continues to deliver electricity to all customers Deregulation and provides meter reading, billing, emergency Effective July 1, 2000, electric customer choice and response, regular maintenance, and balancing competition among electric suppliers was implemented services.

in Maryland. As a result of the deregulation of electric

" BGE transferred, at book value, its generating generation, the following occurred:

assets and related liabilities to the merchant

" All customers can choose their electric energy energy business. At December 31, 2005, BGE supplier. remains contingently liable for the

• BGE provided fixed-price standard offer service $269.8 million outstanding balance for for commercial and industrial customers liabilities transferred to the merchant energy through either June 30, 2002 or June 30, 2004, business.

depending on customer type. For the commercial and industrial customers that did Standard Offer Service not select an alternative supplier after those time periods, BGE provided a market-based BGE is providing fixed-price standard offer service for residential customers that do not select an alternative standard offer service. Base rates for commercial and industrial customers were frozen until supplier through June 30, 2006. Beginning July 1, 2006, BGE's obligation to provide fixed-price standard June 30, 2004.

offer service to residential customers will end, and all residential customers that receive their electric supply from BGE will be charged market-based standard offer service rates.

10

Since July 1, 2004, all commercial and industrial We discuss the market risk of our regulated electric customers that receive their electric supply from BGE business in more detail in Item 7. Managements are charged market-based standard offer service rates. Discussion andAnalysis-Market Risk section.

We discuss market-based standard offer service in more detail below. Electric Load Management BGE has implemented various programs for use when ProviderofLast Resort (POLR) system-operating conditions or market economics BGE is obligated to provide marker-based standard offer indicate that a reduction in load would be beneficial.

service to residential customers from July 1, 2006 We refer to these programs as active load management through May 31, 2010, and for commercial and programs. These programs include:

industrial customers for varying periods beyond

" two options for commercial and industrial June 30, 2004, depending on customer load. The customers to voluntarily reduce their electric POLR rates charged during these time periods recover loads, BGE's wholesale power supply costs and include an

" air conditioning control for residential and administrative fee. The administrative fee includes a commercial customers, and shareholder return component and an incremental cost

" residential water heater control.

component.

These programs generally take effect on summer BGE's obligation to provide market-based standard days when demand and/or wholesale prices are relatively offer service to its largest commercial and industrial high and had the capability during the 2005 summer to customers expired on May 31, 2005. BGE continues to reduce load up to approximately 238 MW.

provide an hourly-priced market-based standard offer service to those customers.

In September 2005, the Maryland PSC issued an Transmission and DistributionFacilities BGE maintains approximately 250 substations and order extending POLR service through May 2007 for those commercial and industrial customers for which 1,300 circuit miles of transmission lines throughout market-based standard offer service was scheduled to central Maryland. BGE also maintains approximately expire at the end of May 2006. The extended service 23,600 circuit miles of distribution lines. The will be provided on substantially the same terms as transmission facilities are connected to those of under the existing service, except that wholesale bidding neighboring utility systems as part of PJM. Under the PJM Tariff and various agreements, BGE and other for service to some customers will be conducted more market participants can use regional transmission frequently.

facilities for energy, capacity, and ancillary services Bidding to supply BGE's market-based standard transactions including emergency assistance.

offer service to commercial and industrial customers We discuss various FERC initiatives relating to beyond May 31, 2006, and to residential customers beyond June 30, 2006, will occur from time to time wholesale electric markets in more detail in Item 7.

Management's Discussion and Analysis-FederalRegulation through a competitive bidding process approved by the section.

Maryland PSC. Successful bidders, which may include subsidiaries of Constellation Energy, will execute contracts with BGE for varying terms depending on the load being served under the contract.

In early 2006, the Maryland PSC commenced a proceeding, and legislation was introduced in the Maryland General Assembly, to consider methods for requiring BGE to defer recovery of some of its costs of providing residential POLR service. These actions are a result of the anticipated increase in POLR prices expected to take place upon the expiration of the residential rate freeze in June 2006. Any decision by the Maryland PSC or legislation adopted by the Maryland General Assembly, that would defer recovery of, or would not allow BGE to fully recover its costs could have a material impact on our, and BGE's, financial results and liquidity.

11

Electric Operating Statistics 2005 2004 2003 2002 2001 Revenues (In millions)

Residential $1,066.6 $1,015.8 $ 959.0 $ 946.6 $ 885.3 Commercial Excluding Delivery Service Only 722.1 708.9 694.2 776.0 903.0 Delivery Service Only 107.5 78.6 66.1 33.5 -

Industrial Excluding Delivery Service Only 52.8 92.3 137.0 158.7 218.1 Delivery Service Only 28.0 21.3 18.2 10.9 -

System Sales and Deliveries 1,977.0 1.916.9 1,874.5 1,925.7 2,006.4 Other (A) 59.5 50.8 47.1 40.3 33.6 Total $2,036.5 $1,967.7 $1,921.6 $1,966.0 $2,040.0 Distribution Volumes (In thousands)-MWH Residential 13,762 13,313 12,754 12,652 11,714 Commercial Excluding Delivery Service Only 7,847 9,286 9,937 11,840 14,147 Delivery Service Only 7,967 5,767 4,982 2,762 -

Industrial Excluding Delivery Service Only 614 1,429 2,556 3,478 4,445 Delivery Service Only 3,122 2,562 1,780 997 -

Total 33,312 32,357 32,009 31,729 30,306 Customers (In thousands)

Residential 1,084.1 1,072.1 1,061.7 1,052.3 1,040.5 Commercial 114.7 113.6 112.1 110.8 110.9 Industrial 5.0 4.8 4.9 4.9 5.0 Total 1,203.8 1,190.5 1,178.7 1,168.0 1,156.4 (A) Primarily includes network integration transmission service revenues, late payment charges, miscellaneous service fees, and tower leasing revenues.

Operatingstatistics do not reflect the elimination of intercompany transactions.

"Delivery service only" refers to BGEs delivery of commodity that was purchased by the customerfrom an alternate supplier.

12

Gas Business BGE purchases the natural gas it resells to The wholesale price of natural gas as a commodity is customers directly from many producers and marketers.

not subject to regulation. All BGE gas customers have BGE has transportation and storage agreements that the option to purchase gas from alternative suppliers, expire from 2006 to 2028.

including subsidiaries of Constellation Energy. BGE BGE's current pipeline firm transportation continues to deliver gas to all customers within its entitlements to serve BGE's firm loads are 309,053 service territory. This delivery service is regulated by the dekatherms (DTH) per day.

Maryland PSC. BGE's current maximum storage entitlements are BGE also provides customers with meter reading, 235,080 DTH per day. To supplement its gas supply at billing, emergency response, regular maintenance, and times of heavy winter demands and to be available in balancing services. temporary emergencies affecting gas supply, BGE has:

Approximately 50% of the gas delivered on BGE's " a liquefied natural gas facility for the distribution system is for customers that purchase gas liquefaction and storage of natural gas with a from alternative suppliers. These customers are charged total storage capacity of 1,092,977 DTH and a fees to recover the costs BGE incurs to deliver the daily capacity of 311,500 DTH, and customers' gas through our distribution system. " a propane air facility with a mined cavern with In April 2005, BGE filed an application for a a total storage capacity equivalent to 564,200

$52.7 million annual increase in its gas base rates. The DTH and a daily capacity of 85,000 DTH.

Maryland PSC issued an order in December 2005 BGE has under contract sufficient volumes of granting BGE an annual increase of $35.6 million. propane for the operation of the propane air facility and Certain parties to the proceeding have sought judicial is capable of liquefying sufficient volumes of natural gas review and Maryland PSC rehearing of the decision. during the summer months for operations of its BGE will not seek review of any aspect of the order. liquefied natural gas facility during peak winter periods.

We cannot provide assurance that a court will not BGE historically has been able to arrange reverse any aspect of the order or that it will not short-term contracts or exchange agreements with other remand certain issues to the Maryland PSC. gas companies in the event of short-term disruptions to For customers that buy their gas from BGE, there gas supplies or to meet additional demand.

is a market-based rates incentive mechanism. Under this BGE also participates in the interstate markets by market-based rates incentive mechanism, our actual cost releasing pipeline capacity or bundling pipeline capacity of gas is compared to a market index (a measure of the with gas for off-system sales. Off-system gas sales are market price of gas in a given period). The difference low-margin direct sales of gas to wholesale suppliers of between our actual cost and the market index is shared natural gas outside BGE's service territory. Earnings equally between shareholders and customers. BGE must from these activities are shared between shareholders secure fixed-price contracts for at least 10%, but not and customers. BGE makes these sales as part of a more than 20%, of forecasted system supply program to balance our supply of, and cost of, natural requirements for the November through March period. gas.

These fixed-price contracts are not subject to sharing under the market-based rates incentive mechanism.

13

Gas Operating Statistics 2005 2004 2003 2002 2001 Revenues (In millions)

Residential Excluding Delivery Service Only $ 558.5 $ 478.0 $ 444.5 $ 342.1 $ 378.4 Delivery Service Only 23.2 14.2 13.6 16.5 16.3 Commercial Excluding Delivery Service Only 174.4 135.4 128.6 89.4 115.5 Delivery Service Only 31.9 28.0 24.6 29.2 21.4 Industrial Excluding Delivery Service Only 10.5 9.4 11.5 9.3 12.8 Delivery Service Only 12.4 7.8 11.4 13.9 13.8 System Sales and Deliveries 810.9 672.8 634.2 500.4 558.2 Off-System Sales 154.7 77.2 84.8 74.8 113.6 Other 7.2 7.0 7.0 6.1 8.9 Total $ 972.8 $ 757.0 $ 726.0 $ 581.3 $ 680.7 Distribution Volumes (In thousands)--DTH Residential Excluding Delivery Service Only 39,107 39,080 40,894 35,364 33,147 Delivery Service Only 5,423 6,053 6,640 6,404 7,201 Commercial Excluding Delivery Service Only 14,133 13,248 13,895 11,583 12,334 Delivery Service Only 28,993 34,120 29,138 28,429 25,037 Industrial Excluding Delivery Service Only 921 865 1,143 1,207 1,386 Delivery Service Only 19,357 14,310 18,399 23,689 23,872 System Sales and Deliveries 107,934 107,676 110,109 106,676 102,977 Off-System Sales 17,209 9,914 12,859 18,551 20,012 Total 125,143 117,590 122,968 125,227 122,989 Customers (In thousands)

Residential 590.9 582.0 575.2 567.3 558.7 Commercial 42.0 41.6 41.1 40.7 40.2 Industrial 1.2 1.2 1.2 1.3 1.4 Total 634.1 624.8 617.5 609.3 600.3 Operatingstatistics k not reflect the elimination of intercompany transactions.

"Delivery service only' refers to BGEs delivery of commodity that was purchasedby the customerfrom an alternatesupplier.

14

Franchises Environmental Matters BGE has nonexclusive electric and gas franchises to use The development (involving site selection, streets and other highways that are adequate and environmental assessments, and permitting),

sufficient to permit them to engage in their present construction, acquisition, and operation of electric business. Conditions of the franchises are satisfactory. generating and distribution facilities are subject to extensive federal, state, and local environmental and Other Nonregulated Businesses land use laws and regulations. From the beginning Energy Projects and Services phases of development to the ongoing operation of We offer energy projects and services designed primarily existing or new electric generating and distribution to provide energy solutions to large commercial and facilities, our activities involve compliance with diverse industrial and governmental customers. These energy laws and regulations that address emissions and impacts products and services include: to air and water, protection of natural and cultural

" designing, constructing, and operating heating, resources, and chemical and waste handling and cooling, and cogeneration fcilities, disposal.

" energy consulting and power-quality services, We continuously monitor federal, state, and local

" services to enhance the reliability of individual environmental initiatives to determine potential impacts electric supply systems, and on our financial results. As new laws or regulations are

" customized financing alternatives. promulgated, we assess their applicability and implement the necessary modifications to our facilities Home Products and Gas Retail Marketing or their operation to maintain on-going compliance.

We offer services to customers in Maryland including: Our capital expenditures were approximately

" home improvements, $170 million during the five-year period 2001-2005 to

" the service of heating, air conditioning, comply with existing environmental standards and plumbing, electrical, and indoor air quality regulations. Our estimated environmental capital systems, and requirements for the next three years are approximately

" the sale of natural gas to residential customers. $40 million in 2006, $200 million in 2007, and

$330 million in 2008.

Other Our other nonregulated businesses include investments Air Quality that we do not consider to be core operations. These The Clean Air Act created the basic framework for the include financial investments and real estate projects. federal and state regulation of air pollution. The While our intent is to dispose of these assets, market cornerstone of the Act is the requirement that National conditions and other events beyond our control may Ambient Air Quality Standards be established to protect affect the actual sale of these assets. However, a future public health and public welfare. In addition, the Act decline in the fair value of these assets could result in also includes technology-driven emission requirements.

losses. Many of these provisions could materially affect our In the fourth quarter 2005, we sold our interests facilities and are described in more detail below.

in our Panamanian distribution facility and the fund that holds interests in two South American energy NationalAmbient Air Quality Standards (NAAQS) projects. We discuss this sale in more detail in Note 2 to The NAAQS are federal air quality standards that the ConsolidatedFinancialStatements. establish maximum ambient air concentrations for the following specific pollutants: ozone (smog), carbon Consolidated Capital Requirements monoxide, lead, particulates, sulfur dioxides (SO2), and Our total capital requirements for 2005 were nitrogen dioxides (NO,). Our generating facilities are

$1,032 million. Of this amount, $741 million was used primarily affected by ozone and particulates standards.

in our nonregulared businesses and $291 million was Ozone is formed when sunlight interacts with emissions used in our regulated business. We estimate our total of nitrogen oxides (NO,) and volatile organic capital requirements will be $1,345 million in 2006. compounds (such as from motor vehicle exhaust). Our We continuously review and change our capital generating facilities are subject to various permits and expenditure programs, so actual expenditures may vary programs meant to achieve or preserve attainment of from the estimate above. We discuss our capital the standards for all these pollutants.

requirements further in Item 7. Management! Discussion In order for states to achieve compliance with the and Analysis-CapitalResources section. 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 S02 and NO. emissions from fossil 15

fuel-fired generating facilities located primarily in the Maryland and Pennsylvania, where we own several Eastern United States. The NO, reduction requirements generating facilities, will, at a minimum, adopt CAIR.

will be phased-in starting in 2009 with both annual As a result, we believe the adoption of the regional haze and ozone season reduction requirements. The phase-in rules by the EPA will not have a material effect on our will be complete by 2015. The SO2 reduction financial results.

requirements will be phased-in starting in 2010 with Several states in the northeastern U.S., including the phase-in complete by 2015. According to the EPA, Maryland, continue to advocate for more stringent and when fully implemented, CAIR will reduce SO2 earlier SO 2 and NO. emissions reductions than those emissions in the affected states by over 70 percent and required under CAIR, the Clean Air Mercury Rule reduce NO, emissions by over 60 percent from 2003 (CAMR), or other federally proposed legislative levels. Although CAIR provides the overall reduction initiatives (such as the Bush Administration's Clear Skies requirements for SO2 and NO., we do not yet know proposal). These states have argued that such additional the impact on our facilities as that will be determined reductions are necessary to achieve compliance with the by the affected states in which our facilities operate. NAAQS for ozone and fine particulate matter by 2010.

Based on the information currently available to us In January 2006, the Maryland Department of the about CAIR, we will install additional air emission Environment (MDE) proposed the Clean Power Rule control equipment at our coal-fired generating facilities (CPR). In addition, a bill entitled the Healthy Air Act in Maryland and at our co-owned coal-fired facilities in (HAA) was introduced in both houses of the Maryland Pennsylvania to meet air quality standards. We include legislature in January 2006. The CPR and the HAA in our estimated environmental capital requirements would require more stringent and earlier reductions of capital spending for these projects, which we expect will SO2 , NO. and mercury than required by CAIR and be approximately $40 million in 2006, $185 million in CAMR. The HAA also contains provisions for the 2007, $300 million in 2008 and $200 million from reduction of carbon dioxide (CO2 ) from coal-fired 2009-2010. Our estimates are subject to significant power plants in Maryland based upon concerns over uncertainties including the timing of any additional global climate change. We are currently. evaluating the federal and/or state regulations or legislation, the potential impact of the CPR and the HAA on our implementation timetables for such regulation or environmental capital expenditure estimates and our legislation, and the specific amount of emissions financial results. While we do not know whether the reductions that will be required at our facilities. As a CPR or the HAA will be enacted; if either is enacted, result, we cannot predict our capital spending or the our compliance costs could be material.

scope or timing of these projects with certainty, and the HazardousAir Emissions actual expenditures, scope and timing could differ The Clean Air Act requires the EPA to evaluate the significantly from our estimates. In addition, CAIR is public health impacts of hazardous air emissions from subject to legal challenges filed by the states and electric steam generating facilities. In March 2005, the industry and environmental groups. We cannot predict EPA finalized regulations to reduce the emissions of the timing or outcome of these challenges, or their mercury from coal-fired facilities. Under CAMR, the possible effect on our financial results.

EPA has decided to regulate mercury through a market-In May 2005, the EPA adopted a stricter NAAQS based cap and trade program that will reduce for ozone. States will be required to submit plans to the nationwide utility emissions of mercury in two phases.

EPA to meet the new standard by 2007, at which time The final CAMR does not address emissions of nickel the standard will take effect. We are unable to and the EPA has not re-proposed regulating such determine the impact that complying with the stricter emissions. The first phase of the program will begin in NAAQS for ozone will have on our financial results 2010. Additional mercury reductions will be required in until the states in which our generating facilities are the second phase of the program starting in 2018.

located adopt plans to meet the new standard. In According to the EPA, the CAMR will reduce mercury transitioning to the stricter NAAQS for ozone, the EPA emissions from all affected coal-fired power plants by has delayed the requirement that states impose fees on about 19 percent from 1999 levels in 2010, mostly generating facilities located in areas that have not met from controls installed to comply with CAIR. The EPA the NAAQS for ozone. Such fees could have been expects total mercury reductions from all affected assessed on certain of our generating facilities located in coal-fired plants of about 69 percent from 1999 levels Maryland and California beginning in 2006, but now by 2018.

will not be assessed prior to 2010.

The CAMR will affect all coal or waste coal fired In June 2005, the EPA finalized its rules relating boilers at our generating facilities. Although our to regional haze, which address emissions of SO2 , NO,.

planned capital expenditures for compliance with CAIR and particulate matter. However, adoption of CAIR by are anticipated to enable us to substantially meet the states is expected to meet the emissions reduction mercury reduction requirements under the first phase of requirements under the regional haze rules. We expect 16

the cap and trade program, the overall cost of Global Climate Change compliance with the CAMR, including complying with Future initiatives regarding greenhouse gas emissions the requirements under the second phase of the and global warming continue to be the subject of much program, could be material. CAMR is subject to legal debate. As a result of our diverse fuel portfolio, our challenges filed by the states, industry, and contribution to greenhouse gases varies by plant type.

environmental groups. We cannot predict the timing or Fossil fuel-fired power plants are significant sources of outcome of these challenges, or their possible effect on CO, emissions, a principal greenhouse gas. Our our financial results. As discussed on the previous page, compliance costs with any mandated federal greenhouse regulatory (CPR) and legislative proposals (HAA) in gas reductions in the future could be material.

Maryland would require more stringent and earlier mercury reductions than required by CAMR. We are Water Quality currently evaluating the potential impact of CAMR, The Clean Water Act established the basic framework CPR, and HAA on our financial results and on our for federal and state regulation of water pollution environmental capital expenditure estimates. control. The Act requires facilities that discharge waste or storm water into the waters of the United States to New Source Review obtain permits requiring them to meet effluent limits in The EPA and several states filed lawsuits against a order to achieve ambient water quality standards in the number of coal-fired power plants primarily in receiving waters. Under current provisions of the Clean Mid-Western and Southern states alleging violations of Water Act, existing discharge permits are renewed every the Prevention of Significant Deterioration and five years, at which time permit effluent limits come Non-Attainment provisions of the Clean Air Act's new under extensive review and can be modified to account source review requirements. The EPA requested for more stringent regulations. In addition, the permits information relating to modifications made to our can be modified at any time.

Brandon Shores, Crane, and Wagner plants located in Maryland. The EPA also sent similar, but narrower, Water Intake Regulations information requests to two of our newer Pennsylvania In July 2004, the EPA published final rules under the waste-coal burning plants in which we have an Clean Water Act that require cooling water intake ownership interest. We have responded to the EPA, and structures to reflect the best technology available for as of the date of this report the EPA has taken no minimizing adverse environmental impacts. The final further action. rules require the installation of additional intake screens Based on the level of emissions control that the or other protective measures, as well as extensive EPA and states are seeking in these new source review site-specific study and monitoring requirements. We enforcement actions, we believe that material additional currently have six facilities affected by the regulation.

costs and penalties could be incurred, and planned The rule allows for a number of compliance options capital expenditures could be accelerated, if the EPA that will be assessed through 2007, following which we was successful in any future actions regarding our will determine whether any action is required and what facilities. our most viable options are if any action is required.

In August 2003, the EPA's equipment replacement Until we determine our most viable option under the rule was promulgated. The rule establishes an final rules, we cannot estimate our compliance costs.

equipment replacement cost threshold for determining However, the costs associated with the final rules could when major new source review requirements are be material.

triggered. The rule provides that plant owners may spend up to 20% of the replacement value of a Hazardousand Solid Waste generation unit on certain component replacements The Comprehensive Environmental Response, each year without triggering requirements for new Compensation and Liability Act (CERCLA) established pollution controls. A legal challenge to this rule was the basic framework for federal and state regulations filed with the United States Court of Appeals and a stay that can require any individual or entity that may have was issued which delayed its effective date. The EPA owned or operated a disposal site, as well as transporters has also determined to seek additional comment on or generators of hazardous substances sent to such site, certain features of the rule, induding the 20% to share in remediation costs. Except to the extent threshold. We cannot predict the timing or outcome of discussed in Note 12 to the ConsolidatedFinancial the legal challenge or the EPA comment process, or Statements, compliance with CERCLA requirements is their possible effect on our financial results. not expected to have a material adverse effect on our financial results.

The Resource Conservation and Recovery Act (RCRA) gives the EPA authority to control hazardous waste from "cradle-to-grave." This includes the 17

generation, transportation, treatment, storage, and impoundments, and sand and gravel mines used for ash disposal of hazardous waste. RCRA also sets forth a management. Depending on the scope of any final framework for the management of non-hazardous requirements, our compliance costs could be material.

wastes. Although RCRA focuses only on active and As a result of these regulatory proposals, the future facilities and, unlike CERCLA, does not address remaining ash placement capacity at our current mine abandoned or historical sites, there are provisions that reclamation site and our current ash generation require phasing-out land disposal of hazardous waste, projections, we are exploring our options for the more stringent hazardous waste management standards, placement of ash, including construction of an ash and a comprehensive underground storage tank placement facility. Over the next five years, we estimate program. that our capital expenditures for this project will be Our coal-fired generating facilities produce approximately $75 million. Our estimates are subject to approximately two and a half million tons of significant uncertainties including the timing of any combustion by-products ("ash") each year, including regulatory change, its implementation timetable, and approximately 850,000 tons at our Maryland plants. Of the scope of the final requirements. As a result, we the two and a half million tons, approximately 75% is cannot predict our capital spending or the scope and beneficially re-used in various projects, including as timing of this project with certainty, and the actual structural fill in surface mine reclamation, and the expenditures, scope and timing could differ significantly remainder is placed in landfills. In 2000, the EPA from our estimates.

decided not to regulate combustion ash as a hazardous waste under RCRA. Instead, the EPA announced its Employees intention to develop national standards, currently Constellation Energy and its subsidiaries had scheduled to be proposed in June 2006, to regulate this approximately 9,850 employees at December 31, 2005.

material as a non-hazardous waste, and is developing At the Nine Mile Point facility, approximately 680 regulations governing the placement of ash in landfills, employees are represented by the International surface impoundments, and sand/gravel surface mines. Brotherhood of Electrical Workers, Local 97. The labor The EPA is also developing regulations for ash contract with this union expires in June 2006. We placement in coal mines, which are expected to be expect negotiations for a new contract to begin in proposed in October 2007. Federal regulation has the May 2006. We expect to execute a new agreement with potential to result in additional requirements such as the union. We believe that our relationship with this groundwater monitoring, liners, and leachate collection union is satisfactory, but there can be no assurances that and treatment systems for all landfills, surface this will continue to be the case.

18

Item IA. Risk Factors " seasonality, You should consider carefily the following risks, along " electricity usage, with the other information contained in this Form 10-K " illiquid markets, The risks and uncertaintiesdescribed below are not the

• transmission or transportation constraints or only ones that may affect us. Additional risks and inefficiencies, uncertaintiesalso may adversely affect our business and " availability of competitively priced alternative operations including those discussed in Item 7 energy sources, Management's Discussion and Analysis. If any of the " demand for energy commodities, following events actually occur, our business andfinancial

• available supplies of natural gas, crude oil and results could be materially adversely affected refined products, and coal,

" generating unit performance, Our merchant energy business may Incur " natural disasters, terrorism, wars, embargoes and substantial costs and liabilities and be exposed other catastrophic events, to price volatility as a result of its participation " federal and state energy and environmental In the wholesale energy markets. regulation, legislation and policies, We buy and sell electricity in both the wholesale " geopolitical concerns affecting global supply of bilateral markets and spot markets, which expose us to oil and natural gas, and the risks of rising and failing prices in those markets,

" general economic conditions, including and our cash flows may vary accordingly. At any given downturns in the United States economy, time, the wholesale spot-market price of electricity for which impact energy consumption.

each hour is generally determined by the cost of In addition to the risks discussed above, risks supplying the next unit of electricity to the market specifically affecting our success in competitive during that hour. This is highly dependent on the wholesale markets include the ability to efficiently regional generation market. In many cases, the next unit operate generating assets, maintenance of the qualifying of electricity supplied would be supplied from facility status of certain projects, transmission and generating stations fueled by fossil fuels, primarily coal, transportation availability, competition from new natural gas, and oil. Consequently, the open market sources of generation, and the level of generation wholesale price of electricity may reflect the cost of capacity. Our inability or failure to effectively hedge our coal, natural gas, or oil plus the cost to convert the fuel assets or positions against changes in commodity prices, to electricity and an appropriate return on capital.

interest rates, counterparty credit risk, or other risk Therefore, changes in the supply and cost of coal, measures could significantly impact our future financial natural gas, and oil may impact the open market results.

wholesale price of electricity.

A portion of our power generation facilities operate The operation of power generation facilities, wholly or partially without long-term power purchase including nuclear facilities, Involves significant agreements. As a result, power from these facilities is risks that could adversely affect our financial sold on the spot market or on a short-term contractual results.

basis, which if not fully hedged may affect the volatility The operation of power generation facilities involves of our financial results. In addition, our business many risks, including start up risks, breakdown or depends upon transmission facilities owned and failure of equipment, transmission lines, substations or operated by others; if transmission is disrupted or pipelines, use of new technology, the dependence on a capacity is inadequate or unavailable, our ability to sell specific fuel source, including the transportation of fuel, and deliver our wholesale power may be limited. or the impact of unusual or adverse weather conditions Currently, our power generation facilities purchase (including natural disasters such as hurricanes) or a portion of their fuel through short-term contracts or environmental compliance, as well as the risk of on the spot market. Fuel prices may also be volatile, performance below expected or contracted levels of and the price that can be obtained for power sales may output or efficiency. This could result in lost revenues not change at the same rate as changes in fuel costs. and/or increased expenses. Insurance, warranties, or Also, our competitive energy businesses expose us to performance guarantees may not cover any or all of the other risks, including credit risk and other.risks relating lost revenues or increased expenses, including the cost to counterparties' failure to perform, and to the risk of of replacement power. A portion of our generation commodity price fluctuations. Fuel price increases and facilities were constructed many years ago. Older defaults by suppliers and other counterparties may generating equipment may require significant capital adversely affect our financial results. expenditures to keep it operating at peak efficiency.

Volatility in market prices for fuel and electricity This equipment is also likely to require periodic may result from among other things: upgrading and improvement. Breakdown or failure of

• weather conditions, one of our operating facilities may prevent the facility 19

from performing under applicable power sales significantly higher than the liabilities recorded by us.

agreements which, in certain situations, could result in Also, our subsidiaries are currently involved in termination of the agreement or incurring a liability for proceedings relating to sites where hazardous substances liquidated damages. have been released and may be subject to additional proceedings in the future.

We are subject to numerous environmental laws We are subject to legal proceedings by individuals and regulations that require capital alleging injury from exposure to hazardous substances expenditures, Increase our cost of operations and could incur liabilities that may be material to our and may expose us to environmental liabilities. financial results. Additional proceedings could be filed We are subject to extensive federal, state, and local against us in the future.

environmental statutes, rules and regulations relating to We may also be required to assume environmental air quality, water quality, waste management, wildlife liabilities in connection with future acquisitions. As a protection, the management of natural resources, and result, we may be liable for significant environmental the protection of human health and safety that could, remediation costs and other liabilities arising from the among other things, require additional pollution control operation of acquired facilities, which may adversely equipment, limit the use of certain fuels, restrict the affect our financial results.

output of certain facilities, or otherwise increase costs.

Significant capital expenditures, operating and other We are exposed to risks relating to the costs are associated with compliance with environmental ownership and operation of nuclear power requirements, and these expenditures and costs could plants.

become even more significant in the future as a result We own and operate nuclear power plants. Ownership of regulatory changes. and operation of these plants expose us to risks in For example, the Environmental Protection Agency addition to those that result from owning and operating (EPA) recently adopted the Clean Air Interstate Rule non-nuclear power generation facilities. Risks associated (CAIR), which requires further reductions of sulfur specifically with the operation and cost of operation of dioxide and nitrogen oxide emissions from fossil nuclear plants include changing federal and state fuel-fired plants located primarily in the Eastern United environmental requirements relating specifically to States, where many of our plants are located, and the nuclear facilities, safety, terrorism, accidents at the Clean Air Mercury Rule (CAMR), which will regulate nuclear plants, storage and ultimate disposal of spent mercury emissions from coal-fired plants through a cap nuclear fuel, disposal of hazardous materials and waste, and trade program. In addition, the State of Maryland monitoring of discharges into the environment, and any is considering requiring additional requirements to required remediation of any site that is identified as further reduce emissions of sulfur dioxide, nitrogen contaminated.

oxide, carbon dioxide, and mercury from generating Any of these risks could result in substantial facilities located in that state. Because CAIR and liabilities or expenses for us and reduce our earnings or CAMR are still in the process of being implemented by harm our liquidity. In addition, the Nuclear Regulatory the affected states and the additional Maryland Commission (NRC) has the authority to modify, requirements are in the proposal stage, we do not yet suspend or revoke the operating license for any of our know the precise impact on our financial results. The nuclear power facilities if it determines that such action capital expenditures and compliance costs with new air is necessary to ensure the public health and safety. Such emission standards could be significantly greater than action would have a negative impact on our financial currently estimated. results.

The EPA also issued a rule under the Clean Water In the event of a nuclear accident at one of our Act that will require certain of our plants to implement nuclear plants, the cost of property damage and other "best technology available" to minimize adverse effects expenses incurred may exceed our insurance coverage to fish and shellfish from cooling water intake structures available from both private sources and an industry at those plants. The capital expenditures and mutual insurance company. In addition, in the event of compliance costs with the Clean Water Act intake an accident at one of our or another participating requirements could be material to our financial results. insured party's nuclear plants, we could be assessed We are subject to liability under environmental retrospective insurance premiums. Uninsured losses or laws for the costs of remediating environmental the payment of retrospective insurance premiums could contamination. Remediation activities include the each have a material adverse effect on our financial cleanup of current facilities and former properties, results.

including manufactured gas plant operations and offsite waste disposal facilities. The remediation costs could be 20

DGE may not be able to recover costs Incurred in Reduced liquidity in the markets in which we satisfying its provider of last resort (POLR) operate could Impair our ability to appropriately obligations, which may adversely affect our, or manage the risks of our operations.

OGE's, financial results and liquidity. Over the past several years, several merchant energy Under the electric restructuring the state of Maryland businesses have ended or significantly reduced their enacted in 1999 and various settlements approved by activities as a result of several factors including the Maryland Public Service Commission (Maryland government investigations, changes in market design PSC) in 2003 and 2005, BGE is obligated to serve as and deteriorating credit quality. As a result, several the POLR for all retail customers in its service regional energy markets experienced a significant decline territories for various periods ending between 2007 and in liquidity. While we have seen recent improvements in 2010. POLR obligations are the obligations of energy liquidity, future reductions in liquidity may restrict our delivery businesses to provide electricity to customers ability to manage our risks, and could impact our that do not choose a competitive supplier and, by their financial results.

nature, are difficult to quantify.

As the POLR supplier, BGE is required to secure We may not fully hedge our generation assets, load requirements through a wholesale bidding process competitive supply or other market positions sufficient to serve those customers in its service territory against changes In commodity prices, and our in the event that customers do not choose alternate hedging procedures may not work as planned.

suppliers or if a third-party supplier is unable to satisfy To lower our financial exposure related to commodity its obligations. The settlements provide that BGE be price fluctuations, we routinely enter into contracts to able to recover all of its supply and certain other actual hedge a portion of our purchase and sale commitments, costs of providing POLR service. weather positions, fuel requirements, inventories of However, in early 2006, the Maryland PSC natural gas, coal and other commodities, and commenced a proceeding, and legislation was competitive supply. As part of this strategy, we routinely introduced in the Maryland General Assembly, to utilize fixed-price forward physical purchase and sales consider methods for requiring BGE to defer recovery contracts, futures, financial swaps, and option contracts of some of its costs of providing residential POLR traded in the over-the-counter markets or on exchanges.

service. These actions are a result of the anticipated However, we may not cover the entire exposure of our increase in POLR prices expected to take place upon assets or positions to market price volatility and the the expiration of the residential rate freeze in coverage will vary over time. Fluctuating commodity June 2006. Any decision by the Maryland PSC, or prices may negatively impact our financial results to the legislation adopted by the Maryland General Assembly, extent we have unhedged positions.

that would defer recovery of, or would not allow BGE Our risk management policies and procedures may to fully recover its costs could have a material impact not always work as planned. As a result of these and on our financial results and liquidity. other factors, we cannot predict with precision the impact that risk management decisions may have on We often rely on single suppliers and at times on our financial results.

single customers, exposing us to significant We are exposed to the risk of loss from financial risks if either should fall to perform counterparties' nonperformance. Nonperformance could their obligations. be failure to provide energy or failure to pay for energy We often rely on a single supplier for the provision of we provide a counterparty. Should counterparties fail to fuel, water, and other services required for operation of provide energy, we might be forced to enter into a facility, and at times, we rely on a single customer or alternative arrangements or honor the underlying a few customers to purchase all or a significant portion commitment at then-current market prices, which may of a facility's output, in some cases under long-term result in higher costs to us. If the counterparties fail to agreements that provide the support for any project pay for energy we provided, then our liquidity and debt used to finance the facility. The failure of any one financial results may be negatively impacted.

customer or supplier to fulfill its contractual obligations In connection with our operations, we have, and could negatively impact our financial results. will continue to, guarantee or indemnify the Consequently, our financial performance depends on performance of a portion of the obligations of our the continued performance by customers and suppliers subsidiaries. Some of these guarantees and indemnities of their obligations under these long-term agreements. are for fixed amounts, others have a fixed maximum amount, and others do not specify a maximum amount.

We might not be able to satisfy all of these guarantees and indemnification obligations if they were to come due at the same time.

21

We operate In deregulated segments of the Such disruptions could also hinder our providing electric and gas Industries created by electricity or natural gas to our retail electric and gas restructuring Initiatives at both state and federal customers and may materially adversely affect our levels. If competitive restructuring of the electric financial results.

or gas industries is reversed, discontinued or delayed, our business prospects and financial results could be materially adversely affected. Our merchant energy business has contractual obligations to certain customers to provide full The regulatory environment applicable to the electric requirements service, which makes it difficult to and gas industries has undergone substantial changes predict and plan for load requirements and may over the past several years as a result of restructuring result in increased operating costs to our initiatives at both the state and federal levels. These business.

initiatives have had a significant impact on the nature Our merchant energy business has contractual of the electric and gas industries and the manner in obligations to certain customers to supply requirements which their participants conduct business. We have service to such customers to satisfy all or a portion of targeted the deregulated segments of the electric and gas their energy requirements. The uncertainty regarding industries created by these initiatives. These changes are the amount of load that our merchant energy business ongoing and we cannot predict the future development must be prepared to supply to customers may increase of deregulation in these markets or the ultimate effect our operating costs. A significant under- or that this changing regulatory environment will have on over-estimation of load requirements could result in our our business. merchant energy business not having enough or having Moreover, existing regulations may be revised or too much power to cover its load obligation, in which reinterpreted, new laws and regulations may be adopted case it would be required to buy or sell power from or or become applicable to us or our facilities, and future to third parties at prevailing market prices. Those prices changes in laws and regulations may have a detrimental may not be favorable and thus could increase our effect on our business. Certain restructured markets operating costs.

(most notably California) have experienced supply problems and price volatility in the past. These supply Our financial results may fluctuate on a seasonal problems and volatility have been the subject of a and quarterly basis.

significant amount of publicity, much of which has Our business is affected by seasonal weather conditions.

been critical of the restructuring initiatives. In some of Consequently, our overall operating results may these markets, including California, proposals have been fluctuate substantially on a seasonal basis, and the made by governmental agencies and/or other interested pattern of this fluctuation may change depending on parties to re-regulate areas of these markets which have the nature and location of any facility we acquire and previously been deregulated. Other proposals to the terms of any contract to which we become a party.

re-regulate may be made and legislative or other Weather conditions directly influence the demand for attention to the electric and gas restructuring process electricity and natural gas and affect the price of energy may delay or reverse the deregulation process. If commodities.

competitive restructuring of the electric and gas markets Generally, demand for electricity peaks in winter is reversed, discontinued or delayed, our business and summer and demand for gas peaks in the winter.

prospects and financial results could be negatively Typically, when winters are warmer than expected and impacted. summers are cooler than expected, demand for energy is lower, resulting in less electric and gas consumption Our financial results may be harmed if than forecasted. Depending on prevailing market prices transportation and transmission availability is for electricity and gas, these and other unexpected limited or unreliable. conditions may reduce our revenues and results of We depend on transportation and transmission facilities operations. First and third quarter financial results, in owned and operated by utilities and other energy particular, are substantially dependent on weather companies to deliver the electricity, coal, and natural gas conditions, and may make period comparisons less we sell to the wholesale and retail markets, as well as relevant.

the natural gas and coal we purchase to supply some of our generating facilities. The Federal Energy Regulatory A downgrade In our credit ratings could Commission (FERC) requires wholesale electric negatively affect our ability to access capital transmission services to be offered on an open access, and/or operate our wholesale and retail non-discriminatory basis. However, sufficient competitive supply businesses.

transmission services are not always available. If We rely on access to capital markets as a source of transportation or transmission is disrupted, or liquidity for capital requirements not satisfied by transportation or transmission capacity is inadequate, operating cash flows. If any of our credit ratings were to our ability to sell and deliver products may be hindered. be downgraded, especially below investment grade, our 22

ability to raise capital on favorable terms, including the result from higher gas and/or electric costs, could have commercial paper markets, could be hindered, and our an adverse effect on our financial results.

borrowing costs would increase. Additionally, the As a result, the regulatory process may restrict our business prospects of our wholesale and retail ability to grow earnings in certain parts of our business, competitive supply businesses, which in many cases rely can cause delays in or affect business planning and on the creditworthiness of Constellation Energy, would transactions, can increase our costs, and does not be negatively impacted. Some of the factors that affect provide any assurance as to achievement of earnings credit ratings are cash flows, liquidity, and the amount levels.

of debt as a component of total capitalization. We operate in a changing market environment influenced by various legislative and regulatory We, and BGE In particular, are subject to initiatives regarding deregulation, regulation or extensive state and federal regulation that could restructuring of the energy industry, including affect our operations and costs. deregulation of the production and sale of electricity.

We are subject to regulation under environmental laws, We will need to adapt to these changes, which could the Federal Power Act, the Atomic Energy Act of 1954 restrict our ability to continue to grow our nonregulated and the Energy Policy Act of 2005, and certain sections businesses. In addition, we may face increasing of Maryland and other state statutes relating to public competitive pressures in our nonregulated businesses.

utilities, and the operation of electric or natural gas facilities. Changing governmental policies and regulatory Poor market performance will affect our benefit actions can have a significant impact on us, including plan and nuclear decommissioning trust asset those of FERC, the NRC, the Maryland PSC, and the values, which may adversely affect our liquidity utility commissions of other states in which we have and financial results.

operations. State and Federal regulations can impact, Our qualified pension obligations have exceeded the fair among other things, the following- value of our plan assets since 2001. At December 31,

" allowed rates of return, 2005, our qualified pension obligations were

" industry and rate structure, $345.1 million greater than the fair value of our plan

• operation of nuclear power plants, assets. The performance of the capital markets will

" operation and construction of plant facilities, affect the value of the assets that are held in trust to

• operation and construction of transmission satisfy our future obligations under our qualified facilities, pension plans. A decline in the market value of those

" acquisition, disposal, depreciation and assets may increase our funding requirements for these amortization of assets and facilities, obligations, which may adversely affect our liquidity

" transactions between subsidiaries and affiliates, and financial results.

" recovery of fuel and purchased power costs, We are required to maintain funded trusts to

" recovery of storm-related repair costs, satisfy our future obligations to decommission our

" decommissioning costs, nuclear power plants. A decline in the market value of

" return on common equity and equity ratio those assets due to poor investment performance or limits, other factors may increase our funding requirements for

• payment of dividends, and these obligations, which may have an adverse affect on

• present or prospective wholesale and retail our liquidity and financial results.

competition (including but not limited to retail choice and transmission costs). War and threats of terrorism and catastrophic Certain regulatory commissions also have the events that could result from terrorism may Impact our results of operations In unpredictable authority to disallow recovery of any and all costs that ways.

they consider excessive or imprudently incurred. In We do not know the impact that any potential future addition, BGE holds franchise agreements with local terrorist attacks may have on the energy industry in municipalities and counties, and must renegotiate general and on our business in particular. In addition, expiring agreements. These factors may have a negative any retaliatory military strikes or sustained military impact on our business and financial results.

campaign may affect our operations in unpredictable BGE's Maryland distribution rates are subject to ways, such as changes in insurance markets and regulation by the Maryland PSC, and such rates are disruptions of fuel supplies and markets, particularly oil.

effective until new base rates are approved. In addition, The possibility alone that infrastructure facilities, such limited categories of costs are recovered through as electric generation, electric and gas transmission and adjustment charges that are periodically reset to reflect distribution facilities, would be direct targets of, or current costs. Inability to recover material costs not indirect casualties of, an act of terror may affect our included in base rates or adjustment clauses, including operations.

increases in uncollectible customer accounts that may 23

Such activity may have an adverse effect on the If completed, our merger with FPL Group may United States economy in general. A lower level of not achieve Its Intended results.

economic activity might result in a decline in energy We and FPL Group entered into the merger agreement consumption, which may adversely affect our financial with the expectation that the merger would result in results or restrict our future growth. Instability in the various benefits, including, among other things, cost financial markets as a result of terrorism or war may savings and operating efficiencies primarily relating to affect our stock price and our ability to raise capital. the nonregulated businesses. Achieving the anticipated benefits of the merger is subject to a number of We are subject to employee workforce factors uncertainties, including whether the businesses of that could affect our businesses and financial Constellation Energy and FPL Group are integrated in results. an efficient and effective manner. Failure to achieve We are subject to employee workforce factors, including these anticipated benefits could result in increased costs, loss or retirement of key executives or other employees, decreases in the amount of expected revenues generated availability of qualified personnel, collective bargaining by the combined company and diversion of agreements with union employees, and work stoppage management's time and energy and could have an that could affect our financial results. adverse effect on the combined company's business, financial results and prospects.

We may be unable to obtain the approvals required to complete our merger with FPL We will be subject to business uncertainties and Group Inc. (FPL Group) or, In order to do so, the contractual restrictions while the merger with combined company may be required to comply FPL Group Is pending that could adversely affect with material restrictions or conditions. our financial results.

On December 19, 2005, we announced the execution Uncertainty about the effect of the merger with FPL of a merger agreement with FPL Group. Before the Group on employees and customers may have an merger may be completed, shareholder approval will adverse effect on us. Although we intend to take steps have to be obtained by us and by FPL Group. In designed to reduce any adverse effects, these addition, various filings must be made with FERC, uncertainties may impair our ability to attract, retain NRC and various utility regulatory, antitrust and other and motivate key personnel until the merger is authorities in the United States. These governmental completed and for a period of time thereafter, and authorities may impose conditions on the completion, could cause customers, suppliers and others that deal or require changes to the terms, of the merger, with us to seek to change existing business relationships.

including restrictions or conditions on the business, Employee retention and recruitment may be operations, or financial performance of the combined particularly challenging prior to the completion of the company following completion of the merger. These merger, as employees and prospective employees may conditions or changes could have the effect of delaying experience uncertainty about their future roles with the completion of the merger or imposing additional costs combined company. If, despite our retention and on or limiting the revenues of the combined company recruiting efforts, key employees depart or fail to accept following the merger, which could have a material employment with us because of issues relating to the adverse effect on the financial results of the combined uncertainty and difficulty of integration or a desire not company and/or cause either us or FPL Group to to remain with the combined company, our financial abandon the merger. results could be affected.

If we are unable to complete the merger, we still The pursuit of the merger and the preparation for will incur and will remain liable for significant the integration of Constellation Energy and FPL Group transaction costs, including legal, accounting, financial may place a significant burden on management and advisory, filing, printing and other costs relating to the internal resources. The diversion of management merger whether or not it is completed, which we attention away from day-to-day business concerns and estimate to be approximately $40 million. Also, any difficulties encountered in the transition and depending upon the reasons for not completing the integration process could affect our financial results.

merger, including whether we have received or entered In addition, the merger agreement restricts us, into a competing takeover proposal, we may be required without FPL Group's consent, from making certain to pay FPL Group a termination fee of up to acquisitions and taking other specified actions until the

$425 million. The occurrence of either of these events merger occurs or the merger agreement terminates.

individually or in combination could have a material These restrictions may prevent us from pursuing adverse affect on our financial results. otherwise attractive business opportunities and making other changes to our business prior to completion of the merger or termination of the merger agreement.

24

Rem 2. Properties expiration of the rights-of-way does not affect BGE's Constellation Energy's corporate offices occupy ability to use the rights-of-way during the renewal approximately 106,000 square feet of leased office space process.

in Baltimore, Maryland. The corporate offices for most BGE has electric transmission and electric and gas of our merchant energy business occupy approximately distribution lines located:

224,000 square feet of leased office space in another " in public streets and highways pursuant to building in Baltimore, Maryland. We describe our franchises, and electric generation properties on the next page. We also " on rights-of-way secured for the most part by have leases for other offices and services located in the grants from owners of the property.

Baltimore metropolitan region, and for various real All of BGE's property is subject to the lien of property and facilities relating to our generation BGE's mortgage securing its mortgage bonds. All of the projects. generation facilities transferred to our subsidiaries by BGE owns its principal headquarters building BGE on July 1, 2000, along with the stock we own in located in downtown Baltimore. In January 2004, BGE certain of our subsidiaries, are subject to the lien of sold a portion of its headquarters building and is in the BGE's mortgage.

proces of consolidating its operations into the We believe we have satisfactory title to our power remainder of the building. In addition, BGE owns project facilities in accordance with standards generally propane air and liquefied natural gas facilities as accepted in the energy industry, subject to exceptions, discussed in Item 1. Business-Gas Business section. which in our opinion, would not have a material BGE also has rights-of-way to maintain 26-inch adverse effect on the use or value of the facilities.

natural gas mains across certain Baltimore City-owned We also lease office space throughout North property (principally parks) which expired in 2004. America, in the United Kingdom, and in Australia to BGE is in the process of renewing the rights-of-way support our merchant energy business.

with Baltimore City for an additional 25 years. The 25

The following table describes our generating facilities:

Installed  % Capacity Plant Location Capacity (MW) Owned Owned (MW) Primary Fuel (at December 31, 2005)

Mid-Atlantic Rerio, 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 1,001 100.0 1,001 Coal/Oil/Gas C. P.Crane Baltimore Co., MD 399 100.0 399 Oil/Coal Keystone Armstrong and Indiana Cos., PA 1,711 21.0 358 (A) Coal Conernaugh Indiana Co., PA 1,711 10.6 181 (A) Coal Perryman Harford Co., MD 360 100.0 360 Oil/Gas Big Sandy Neal, WV 300 100.0 300 Gas Wolf Hills Bristol, VA 250 100.0 250 Gas Riverside Baltimore Co., MD 249 100.0 249 Oil/Gas Handsome Lake Rockland Twp, PA 250 100.0 250 Gas Notch Cliff Baltimore Co., MD 128 100.0 128 Gas Westport Baltimore City, MD 121 100.0 121 Gas Philadelphia Road Baltimore City, MD 64 100.0 64 Oil Safe Harbor Safe Harbor, PA 416 66.7 278 Hydro Total Mid-Atlantic Region 9,981 6,960 Plants with Power PurchaseAgmements High Desert Victorville, CA 830 100.0 830 Gas Nine Mile Point Unit I Scriba, NY 620 100.0 620 Nudear Nine Mile Point Unit 2 Scriba, NY 1,148 82.0 941 Nuclear R.E. Ginna Ontario, NY 498 100.0 498 Nudear University Park Chicago, IL 300 100.0 300 Gas Total Plants with Power PurchaseAgreements 3,396 3,189 Competitive SApUh Rio Nogales Seguin, TX 800 100.0 800 Gas Holland Energy Shelby Co., IL 665 100.0 665 Gas Total Competitim' Supply 1,465 1,465 Other Panther Creek Nesquehoning. PA 83 50.0 42 Waste Coal Colver Colver Township, PA 110 25.0 28 Waste Coal Sunnyside Sunnyside, UT 53 50.0 26 Waste Coal ACE Trona, CA 102 31.1 32 Coal Jasmin Kern Co., CA 33 50.0 17 Coal POSO Kern Co., CA 33 50.0 17 Coal Mammoth Lakes G-I 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 11 Fallon, NV 10 50.0 5 Geothermal Roddin 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 30 12.2 4 Solar SEGS V Kramer Junction, CA 30 4.2 1 Solar SEGS VI Kramer Junction, CA 30 8.8 3 Solar Total Other 650 242 Total GeneratingFacilities 15,492 11,856 (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.

26

The following table describes our processing facilities:

Primary Plant Location Owned Fuel A/C Fuels Hazelton, PA 50.0 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 IlI 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 the ConsolidatedFinancialStatements.

Item 4. Submission of Matters to Vote of Security Holders Not applicable.

Executive Officers of the Registrant Other Offices or Positions Held Name Age Present Office During Past Five Years Mayo A. Shattuck III 51 Chairman of the Board of Constellation Global Head of Investment Banking and Energy (since July 2002), President Global Head of Private Banking-and Chief Executive Officer of Deutsche Banc Alex. Brown.

Constellation Energy (since November 2001); and Chairman of the Board of BGE (since July 2002)

E. Follin Smith 46 Executive Vice President (since January Senior Vice President-Constellation 2004), Chief Financial Officer (since Energy; and Senior Vice President June 2001) and Chief Administrative and Chief Financial Officer-Officer (since January 2004) of Armstrong Holdings, Inc.

Constellation Energy; and Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company (since January 2002)

Thomas V. Brooks 43 Chairman of Constellation Energy President-Constellation Energy Commodities Group, Inc. (since Commodities Group, Inc.; Executive August 2005); Vice Chairman (since Vice President-Constellation Energy; August 2005) and Executive Vice Vice President of Business President of Constellation Energy Development and Strategy-(since January 2004) Constellation Energy; and Vice President-Goldman Sachs.

Michael J. Wallace 58 President of Constellation Generation Managing Director and Member-Group, LLC (since January 2002); Barrington Energy Partners.

Executive Vice President of Constellation Energy (since January 2004)

Thomas E Brady 56 Executive Vice President, Corporate Senior Vice President, Corporate Strategy and Retail Competitive Strategy and Development-Supply of Constellation Energy (since Constellation Energy; and Vice January 2004) President, Corporate Strategy and Development-Constellation Energy.

27

Other Offices or Positions Held Name Age Present Office During Past Five Years Irving B. Yoskowitz 60 Executive Vice President and General Senior Counsel-Crowell & Moring Counsel of Constellation Energy (law firm); Senior Partner-Global (since June 2005) Technology Partners, LLC (investment banking and consulting firm); and Senior Advisor-Akin Gump Strauss Hauer Feld LLP (law firm).

Felix J. Dawson 38 Co-President and Co-Chief Executive Co-Chief Commercial Officer-Officer of Constellation Energy Constellation Energy Commodities Commodities Group, Inc. (since Group, Inc.; Managing Director-August 2005) Constellation Energy Commodities Group, Inc.; Managing Director, Co-Head Origination-Constellation Energy Commodities Group, Inc.;

and Vice President-Goldman Sachs Power, LLC.

George E. Persky 36 Co-President and Co-Chief Executive Co-Chief Commercial Officer-Officer of Constellation Energy Constellation Energy Commodities Commodities Group, Inc. (since Group, Inc.; Managing Director-August 2005) Constellation Energy Commodities Group, Inc.; Manager, Business Development and Strategy-Constellation Energy; and Associate, Goldman Sachs.

Kenneth W. DeFontes, Jr. 55 President and Chief Executive Officer of Vice President, Electric Transmission Baltimore Gas and Electric Company and Distribution-BGE.

and Senior Vice President of Constellation Energy (since October 2004)

Paul J. Allen 54 Senior Vice President, Corporate Affairs Vice President, Corporate Affairs--

of Constellation Energy (since January Constellation Energy; and Senior Vice 2004) President and Group Head-Ogilvy Public Relations.

John R. Collins 48 Senior Vice President (since January Vice President-Constellation Energy; 2004) and Chief Risk Officer of Managing Director-Finance--

Constellation Energy (since December Constellation Power Source Holdings, 2001) Inc.; and Managing Director and Senior Financial Officer-Constellation Energy Commodities Group, Inc.

Beth S. Perlman 45 Senior Vice President (since January Vice President, Technology-Enron 2004) and Chief Information Officer Corporation.

of Constellation Energy (since April 2002)

Marc L. Ugol 47 Senior Vice President, Human Resources Vice President, Human Resources-of Constellation Energy (since January Constellation Energy; and Senior Vice 2004) 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.

28

PART II Item 5. Market for Registrant's Common Equity and Related Shareholder Matters Stock Trading In January 2006, we announced an increase in our Constellation Energy's common stock is traded under quarterly dividend from $0.335 to $0.3775 per share the ticker symbol CEG. It is listed on the New York, payable April 3, 2006 to holders of record on Chicago, and Pacific stock exchanges. It has unlisted March 10, 2006. This is equivalent to an annual rate of trading privileges on the Boston, Cincinnati, and $1.51 per share.

Philadelphia exchanges. Quarterly dividends were declared on our common As of January 31, 2006, there were 43,709 stock during 2005 and 2004 in the amounts set forth common shareholders of record. below.

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

are no contractual limitations on Constellation Energy " BGE elects to defer interest payments on the paying common stock dividends. 6.20% Deferrable Interest Subordinated Dividends have been paid continuously since 1910 Debentures due 2043, and any deferred interest on the common stock of Constellation Energy, BGE, remains unpaid; or and their predecessors. Future dividends depend upon " any dividends (and any redemption payments) future earnings, our financial condition, and other due on BGE's preference stock have not been factors. paid.

Common Stock Dividends and Price Ranges 2005 2004 Dividend Price* Dividend Price Declared High Low Declared High Low First Quarter .................................... $0.335 $53.55 $43.01 $0.285 $41.47 $38.52 Second Quarter .................................. 0.335 57.91 50.36 0.285 41.35 35.89 Third Quarter ................................... 0.335 62.09 56.50 0.285 41.18 36.76 Fourth Quarter .................................. 0.335 62.60 50.40 0.285 44.90 39.90 Total ........................................... $1.340 $1.140

• Based on New York Stock Exchange Composite Transactions.

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.

Total Number of Shares Maximum Number Purchased as of Shares that Part of Publicly May Yet Be Total Number Announced Purchased Under of Shares Average Price Plans or the Plans and Period Purchased Paid for Shares Programs Programs October 1 - October 31, 2005 889 $55.88 November I - November 30, 2005 123 51.70 L - r .U- L n no' A AIR

.ecem er I - sJecem er 31, 20u0 1s,/oL,'-1 0-7o.. )

Total 1,983,426 $58.33 --

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Item 6. Selected Financial Data Constellation Energy Group, Inc. and Subsidiaries 2005 2004 2003 2002(l) 2001 (In millions, except per share amounts)

Summary of Operations Total Revenues $17,132.0 $12,286.4 $ 9,454.1 $ 4,771.6 $ 3,683.0 Total Expenses 16,073.9 11,261.2 8,431.0 3,711.5 3,267.3 Income From Operations 1,058.1 1,025.2 1,023.1 1,060.1 415.7 Other Income 62.8 25.3 20.7 33.8 0.8 Fixed Charges 310.1 326.8 336.5 277.3 236.0 Income Before Income Taxes 810.8 723.7 707.3 816.6 180.5 Income Taxes 204.1 156.9 250.6 301.2 61.3 Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles 606.7 566.8 456.7 515.4 119.2 Income (Loss) from Discontinued Operations, Net of Income Taxes 23.6 (27.1) 19.0 10.2 (36.8)

Cumulative Effects of Changes in Accounting Principles. Net of Income Taxes (7.2) - (198.4) - 8.5 Net Income $ 623.1 $ 539.7 $ 277.3 $ 525.6 $ 90.9 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles Assuming Dilution $ 3.38 $ 3.28 $ 2.74 $ 3.14 $ 0.75 Income (Loss) from Discontinued Operations 0.13 (0.16) 0.11 0.06 (0.23)

Cumulative Effects of Changes in Accounting Principles (0.04) - (1.19) - 0.05 Earnings Per Common Share Assuming Dilution $ 3.47 $ 3.12 $ 1.66 $ 3.20 $ 0.57 Dividends Declared Per Common Share $ 1.34 $ 1.14 $ 1.04 $ 0.96 $ 0.48 Summary of Financial Condition Total Assets $21,473.9 $17,347.1 $15,593.0 $14,943.3 $14,697.5 Short-Term Borrowings $ 0.7 $ - $ 9.6 $ 10.5 $ 975.0 Current Portion of Long-Term Debt $ 491.3 $ 480.4 $ 343.2 $ 426.2 $ 1,406.7 Capitalization Long-Term Debt $ 4,369.3 $ 4,813.2 $ 5,039.2 $ 4,613.9 $ 2,712.5 Minority Interests 22.4 90.9 113.4 105.3 101.7 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 190.0 190.0 190.0 Common Shareholders' Equity 4,915.5 4,726.9 4,140.5 3,862.3 3,843.6 Total Capitalization $ 9,497.2 $ 9,821.0 $ 9,483.1 $ 8,771.5 $ 6,847.8 Financial Statistics at Year End Ratio of Earnings to Fixed Charges 3.38 3.02 . 2.90 3.31 1.39 Book Value Per Share of Common Stock $ 27.57 $ 26.81 $ 24.68 $ 23.44 $ 23.48 Certainprior-yearamounts have been reclassifiedto conform with the current year! presentation.

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

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

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Baltimore Gas and Electric Company and Subsidiaries 2005 2004 2003 2002 2001 (In millions)

Summary of Operations Total Revenues $3,009.3 $2,724.7 $2,647.6 $2,547.3 $2,720.7 Total Expenses 2,612.8 2,353.3 2,262.6- 2,181.0 2,408.9 Income From Operations 396.5 371.4 385.0 366.3 311.8 Other Income (Expense) 5.9 (6.4) (5.4) 10.7 0.4 Fixed Charges 93.5 96.2 111.2 140.6 154.6 Income Before Income Taxes 308.9 268.8 268.4 236.4 157.6 Income Taxes 119.9 102.5 105.2 93.3 60.3 Net Income 189.0 166.3 163.2 143.1 97.3 Preference Stock Dividends 13.2 13.2 13.2 13.2 13.2 Earnings Applicable to Common Stock $ 175.8 $ 153.1 $ 150.0 $ 129.9 $ 84.1 Summary of Financial Condition Total Assets $4,742.1 $4,662.9 $4,706.6 $4,779.9 $4,954.5 Current Portion of Long-Term Debt $ 469.6 $ 165.9 $ 330.6 $ 420.7 $ 666.3 Capitalization Long-Term Debt $1,015.1 $1,359.5 $1,343.7 $1,499.1 $1,821.7 Minority Interest 18.3 18.7 18.9 19.4 5.0 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 190.0 190.0 190.0 Common Shareholder's Equity 1,622.5 1,566.0 1,487.7 1,461.7 1,131.4 Total Capitalization $2,845.9 $3,134.2 $3,040.3 $3,170.2 $3,148.1 Financial Statistics at Year End Ratio of Earnings to Fixed Charges 4.22 3.75 3.36 2.66 1.99 Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends 3.45 3.08 2.82 2.31 1.75 31

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction and Overview Strategy Constellation Energy Group, Inc. (Constellation Energy) is an We are pursuing a strategy of providing energy and energy energy company that conducts its business through various related services through our competitive supply activities and subsidiaries including a merchant energy business and Baltimore BGE, our regulated utility located in Maryland. Our merchant Gas and Electric Company (BGE). We describe our operating energy business focuses on short-term and long-term purchases segments in Note 3. and sales of energy, capacity, and related products to various This report is a combined report of Constellation Energy customers, including distribution utilities, municipalities, and BGE. References in this report to "we" and "our" are to cooperatives, industrial customers, and commercial customers.

Constellation Energy and its subsidiaries, collectively. References We obtain this energy through both owned and contracted in this report to the "regulated business(es)" are to BGE. We supply resources. Our generation fleet is strategically located in discuss our business in more detail in Item 1. Business section deregulated markets across the country and is diversified by fuel and the risk factors affecting our business in Item ]A. Risk type, including nuclear, coal, gas, oil, and renewable sources. In Factorssection. addition to owning generating facilities, we contract for power In this discussion and analysis, we will explain the general from other merchant providers, typically through power purchase financial condition and the results of operations for agreements. We intend to remain diversified between regulated Constellation Energy and BGE including: transmission and distribution and competitive supply. We will

• factors which affect our businesses, use both our owned generation and our contracted generation to

• our earnings and costs in the periods presented, support our competitive supply operations.

" changes in earnings and costs between periods, We are a leading national competitive supplier of energy. In

" sources of earnings, our wholesale and commercial and industrial retail marketing

" impact of these factors on our overall financial activities we are leveraging our recognized expertise in providing condition, full requirements energy and energy related services to enter

" expected future expenditures for capital projects, and markets, capture market share, and organically grow these

• expected sources of cash for future capital expenditures. businesses. Through the application of technology, intellectual As you read this discussion and analysis, refer to our capital, process improvement, and increased scale, we are seeking Consolidated Statements of Income, which present the results of to reduce the cost of delivering full requirements energy and our operations for 2005, 2004, and 2003. We analyze and energy related services and managing risk.

explain the differences between periods in the specific line items We are also responding proactively to customer needs by of our Consolidated Statements of Income. expanding the variety of products we offer. Our wholesale We have organized our discussion and analysis as follows: competitive supply activities include a growing operation that

" First, we discuss our strategy. markets physical energy products and risk management and

" We then describe the business environment in which we logistics services to generators, distributors, producers of coal, operate including how regulation, weather, and other natural gas and fuel oil, and other consumers.

factors affect our business. As part of our risk management activities, we trade energy

• Next, we discuss our critical accounting policies. These and energy-related commodities and deploy risk capital in the are the accounting policies that are most important to management of our portfolio in order to earn additional returns.

both the portrayal of our financial condition and results These activities are managed through daily value at risk and stop of operations and require management's most difficult, loss limits and liquidity guidelines.

subjective or complex judgment. Within our retail competitive supply activities, we are

" We highlight significant events that are important to marketing a broader array of products and expanding our understanding our results of operations and financial markets. Over time, we may consider integrating the sale of condition. electricity and natural gas to provide one energy procurement

" We then review our results of operations beginning with solution for our customers.

an overview of our total company results, followed by a Collectively, the integration of owned and contracted more detailed review of those results by operating electric generation assets with origination, fuel procurement, and segment. risk management expertise, allows our merchant energy business

" We review our financial condition addressing our to earn incremental margin and more effectively manage energy sources and uses of cash, security ratings, capital and commodity price risk over geographic regions and over time.

resources, capital requirements, commitments, and Our focus is on providing solutions to customers' energy needs, off-balance sheet arrangements. and our wholesale marketing and risk management operation

" We conclude with a discussion of our exposure to adds value to our owned and contracted generation assets by various market risks. providing national market access, market infrastructure, real-time market intelligence, risk management and arbitrage Pending Merger with FPL Group, Inc. opportunities, and transmission and transportation expertise.

In order to further our strategies discussed below, we entered Generation capacity supports our wholesale marketing and risk into an Agreement and Plan of Merger with FPL Group, Inc. management operation by providing a source of reliable power (FPL Group). We discuss our pending merger with FPL Group supply.

in more detail in Note 15. To achieve our strategic objectives, we expect to continue to pursue opportunities that expand our access to customers and to support our wholesale marketing and risk management operation 32

with generation assets that have diversified geographic, fuel, and The impacts of electric deregulation on BGE in Maryland dispatch characteristics. We also expect to grow through buying are discussed in Item I. Business-ElectricRegulatory Matters and and selling a greater number of physical energy products and Competition section.

services to large energy customers. We expect to achieve operating efficiencies within our competitive supply operation Regulation by the Maryland PSC and our generation fleet by selling more products through our In addition to electric restructuring, which is discussed in Item existing sales force, benefiting from efficiencies of scale, adding 1. Business--ElectricRegulatory Matters and Competition section, to the capacity of existing plants, and making our business regulation by the Maryland Public Service Commission processes more efficient. (Maryland PSC) significantly influences BGE's businesses. The We expect BGE and our other retail energy service Maryland PSC determines the rates that BGE can charge businesses to grow through focused and disciplined expansion customers of its electric distribution and gas businesses. The primarily from new customers. At BGE, we are also focused on Maryland PSC incorporates into BGE's standard offer service enhancing reliability and customer satisfaction. rates the transmission rates determined by the Federal Energy Customer choice, regulatory change, and energy market Regulatory Commission (FERC). BGE's electric rates are conditions significantly impact our business. In response, we unbundled in customer billings to show separate components for regularly evaluate our strategies with these goals in mind: to delivery service (i.e. base rates), competitive transition charges improve our competitive position, to anticipate and adapt to the (CTC), electric supply (commodity charge), transmission, a business environment and regulatory changes, and to maintain a universal service surcharge, and certain taxes. The rates for strong balance sheet and investment-grade credit quality. BGE's regulated gas business continue to consist of a delivery We are constantly reevaluating our strategies and might charge (base rate) and a commodity charge.

consider:

" acquiring or developing additional generating facilities Base Rates and gas properties to support our merchant energy Base rates are the rates the Maryland PSC allows BGE to charge business, its customers for the cost of providing them delivery service,

" mergers or acquisitions of utility or non-utility plus a profit. BGE has both electric base rates and gas base rates.

businesses or assets, and Higher electric base rates apply during the summer when the

" sale of assets or one or more businesses. demand for electricity is higher. Gas base rates are not affected by seasonal changes.

Business Environment BGE may ask the Maryland PSC to increase base rates With the evolving regulatory environment surrounding customer from time to time. The Maryland PSC historically has allowed choice, increasing competition, and the growth of our merchant BGE to increase base rates to recover its utility plant investment energy business, various factors affect our financial results. We and operating costs, plus a profit. Generally, rate increases discuss some of these factors in more detail in the Item 1. improve the earnings of our regulated business because they Business-Competitionsection. We also discuss these various allow us to collect more revenue. However, rate increases are factors in the ForwardLooking Statements and Item UA.Risk normally granted based on historical data and those increases Factors sections. may not always keep pace with increasing costs. Other parties Over the last several years, the energy markets have been may petition the Maryland PSC to decrease base rates.

highly volatile with significant changes in natural gas, power, oil, As a result of the deregulation of electric generation in coal, and emission allowance prices. The volatility of the energy Maryland, BGE's residential electric base rates are frozen until markets impacts our credit portfolio; and we continue to actively July 2006. Electric base rates were frozen until July 2004 for manage our credit portfolio to attempt to reduce the impact of a commercial and industrial customers. In early 2006, the potential counteiparty default. We discuss our customer Maryland PSC commenced a proceeding, and legislation was (counterparty) credit and other risks in more detail in the introduced in the Maryland General Assembly, to consider Market Risk section. methods for requiring BGE to defer recovery of some of its costs In addition, the volatility of the energy markets impacts our of providing residential POLR service. These actions are a result liquidity and collateral requirements. We discuss our liquidity in of the anticipated increase in POLR prices expected to take the FinancialCondition section. place upon the expiration of the residential rate freeze in June 2006. Any decision by the Maryland PSC or legislation Competition adopted by the Maryland General Assembly, that would defer We face competition in the sale of electricity, natural gas, and recovery of, or would not allow BGE to fully recover its costs coal in wholesale energy markets and to retail customers. could have a material impact on our, and BGE's, financial results Various states have moved to restructure their electricity and liquidity. We discuss electric deregulation in Item 1.

markets. The pace of deregulation in these states varies based on Business--ElectricRegulatory Matters and Competition section.

historical moves to competition and responses to recent market In April 2005, BGE filed an application for a events. While many states continue to support retail competition $52.7 million annual increase in its gas base rates. The and industry restructuring, other states that were considering Maryland PSC issued an order in December 2005 granting BGE deregulation have slowed their plans or postponed consideration. an annual increase of $35.6 million. Certain parties to the In addition, other states are reconsidering deregulation. proceeding have sought judicial review and Maryland PSC All BGE electricity and gas customers have the option to rehearing of the decision. BGE will not seek review of any purchase electricity and gas from alternate suppliers. aspect of the order. We cannot provide assurance that a court We discuss merchant competition in more detail in Item 1. will not reverse any aspect of the order or that it will not Business--Competition section. remand certain issues to the Maryland PSC.

33

Electric Commodity and Transmission Charges In November 2004, FERC eliminated through and out BGE electric commodity and transmission charges (standard transmission rates between the Midwest Independent System offer service) are discussed in Item 1. Busines--ElectricRegulatory Operators (MISO) and PJM and put in place Seams Elimination Matters and Competition section. ChargelCost Adjustment/Assignment (SECA) transition rates, which are paid by the transmission customers of MISO and Gas Commodity Charge PJM and allocated among the various transmission owners in BGE charges its gas customers separately for the natural gas they PJM and MISO. The SECA transition rates are in effect from purchase. The price BGE charges for the natural gas is based on December 1, 2004 through March 31, 2006. FERC has set for a markect-based rates incentive mechanism approved by the hearing the various compliance filings that established the level Maryland PSC. We discuss market-based rates in more detail in of the SECA rates and has indicated that the SECA rates are the Regulated Gas Business--Gas Cost Adjustments section and in being recovered from the MISO and PJM transmission Note 6. customers subject to refund by the MISO and PJM transmission owners.

Federal Regulation In addition, FERC has indicated that it will provide FERC transmission customers that are charged the SECA rates with an The FERC has jurisdiction over various aspects of our business, opportunity to demonstrate that such charges should be shifted including transmission and wholesale electricity sales. We believe to their wholesale power suppliers. We are a recipient of SECA that FERC's continued commitment to competition in wholesale payments, payer of SECA charges, and supplier to whom such energy markets should result in improved competitive markets charges may be shifted. We are unable to predict the timing or across various regions. outcome of FERC's SECA rate proceeding. However, as the Since 1997, operation of BGE's transmission system has amounts collected under the SECA rates are subject to refund been under the authority of PJM Interconnection (PJM), the and the ultimate outcome of the proceeding establishing SECA Regional Transmission Organization (RTO) for the Mid-Atlantic rates is uncertain, the result of this proceeding may have a region, pursuant to FERC oversight. As the transmission material effect on our financial results.

operator, PJM operates the energy markets and conducts In May 2005, FERC issued an order accepting BGE's joint day-to-day operations of the bulk power system. The liability of application to have network transmission rates established transmission owners, including BGE, and power generators is through a formula that tracks costs instead of through fixed limited to those damages caused by the gross negligence of such rates. The formula approach became effective June 1, 2005, and entities. the implementation of these rates did not have a material effect In addition to PJM, RTOs exist in other regions of the on our, or BGE's, financial results. The use of this formula country, such as the Midwest, New York, and New England. In approach is subject to refund based on the outcome of a hearing addition to operation of the transmission system and before an administrative law judge. The hearing process has been responsibility for transmission system reliability, these RTOs also suspended while the various parties discuss a possible settlement.

operate energy markets for their region pursuant to FERC's We cannot predict the outcome of this proceeding or whether oversight. Our merchant energy business participates in these FERC will ultimately affirm either a settlement or the judge's regional energy markets. These markets are continuing to decision.

develop, and revisions to market structure are subject to review Other market changes are also being considered, including and approval by FERC and other regulatory bodies. We cannot potential revisions to PJM's capacity market and rate design.

predict the outcome of such a review at this time. However, Such changes will be subject to FERC's review and approval. We changes to the structure of these markets could have a material cannot predict the outcome of these proceedings or the possible effect on our financial results. effect on our, or BGE's, financial results at this time.

Recent initiatives at FERC have included a review of its methodology for the granting of market-based rate authority to FederalEnergy Legislation sellers of electricity. FERC has announced new interim tests that The Energy Policy Act of 2005 (EPACT 2005) was signed by will be used to determine the extent to which companies may the President on August 8, 2005. The legislation encourages have market power in certain regions. Where market power is investments in energy production and delivery infrastructure, found to exist, FERC may require companies to implement including further development of competitive wholesale energy measures to mitigate the market power in order to maintain markets, and promotes the use of a diverse mix of fuels and market-based rate authority. In addition, FERC is reviewing renewable technologies to generate electricity, including federal other aspects of its granting of market-based rate authority, support and tax incentives for dean coal, nuclear, and renewable including transmission market power, affiliate abuse, and barriers power generation. Effective February 2006, the legislation to entry. We cannot determine the eventual outcome of FERC's repealed the Public Utility Holding Company Act of 1935 efforts in this regard and their impact on our financial results at (PUHCA 1935).

this time.

34

In addition, there are a number of FERC rulemaking " location of our generating facilities relative to the proceedings that relate to the implementation of EPACT 2005 location of our load-serving obligations, including proceedings relating to FERC's new responsibilities " implementation of new market rules governing following the repeal of PUHCA 1935, its revised merger operations of regional power pools, authority, its new authority over electric grid reliability, and its " procedures used to maintain the integrity of the physical new authority with respect to addressing electric and gas market electricity system during extreme conditions, manipulation. While FERC has moved expeditiously to " changes in the nature and extent of federal and state implement its new authority under EPACT 2005, at this time regulations, and we are unable to predict the ultimate impact of these rules or " intemarional supply and demand.

the possible effect on our business or financial results given that These factors can affect energy commodity and derivative these rules may be subject to further revision or clarification as a prices in different ways and to different degrees. These effects result of requests for rehearing or court appeals but they could may vary throughout the country as a result of regional have a material impact on our financial results. differences in:

There are also rulemakings required from other federal " weather conditions, agencies, the outcome of which could affect our financial results, " market liquidity, but we cannot at this time predict such outcome or the actual " capability and reliability of the physical electricity and effect on our financial results. gas systems,

" local transportation systems, and Weather " the nature and extent of electricity deregulation.

Merchant Energy Business Our merchant energy business contracts for the delivery of Weather conditions in the different regions of North America coal to our coal-fired generation facilities. The timely delivery of influence the financial results of our merchant energy business. coal together with the maintenance of appropriate levels of Weather conditions can affect the supply of and demand for inventory is necessary to allow for continued, reliable generation electricity, gas, and fuels. Changes in energy supply and demand from these facilities. In the second, third, and fourth quarters of may impact the price of these energy commodities in both the 2004, we experienced delays in deliveries from one of the rail spot market and the forward market, which may affect our companies that supplies coal to our generating facilities. In results in any given period. Typically, demand for electricity and response, we procured coal using an alternative delivery method its price are higher in the summer and the winter, when weather to meet our contractual load obligations. We discuss the impact is more extreme. The demand for and price of natural gas and of these delays on our financial results in the Mid-Atlantic oil are higher in the winter. However, all regions of North Region section. The majority of the coal that was not delivered America typically do not experience extreme weather conditions during 2004 was delivered during 2005.

at the same time, thus we are not typically exposed to the effects Other factors also impact the demand for electricity and gas of extreme weather in all parts of our business at once. in our regulated businesses. These factors include the number of customers and usage per customer during a given period. We use BGE these terms later in our discussions of regulated electric and gas Weather affects the demand for electricity and gas for our operations. In those sections, we discuss how these and other regulated businesses. Very hot summers and very cold winters factors affected electric and gas sales during the periods increase demand. Mild weather reduces demand. Weather affects presented.

residential sales more than commercial and industrial sales, The number of customers in a given period is affected by which are mostly affected by business needs for electricity and new home and apartment construction and by the number of gas. The Maryland PSC allows BGE to record a monthly businesses in our service territory.

adjustment to our regulated gas business revenues to eliminate Usage per customer refers to all other items impacting the effect of abnormal weather patterns. We discuss this further customer sales that cannot be measured separately. These factors in the Regulated Gas Business-WeatherNormalization section. include the strength of the economy in our service territory.

When the economy is healthy and expanding, customers tend to Other Factors consume more electricity and gas. Conversely, during an A number of other factors significantly influence the level and economic downturn, our customers tend to consume less volatility of prices for energy commodities and related derivative electricity and gas.

products for our merchant energy business. These factors include: Environmental Matters and Legal Proceedings

" seasonal daily and hourly changes in demand, We discuss details of our environmental matters in Note 12 and

• number of market participants, Item 1. Business-EnvironmentalMatters section. We discuss

" extreme peak demands, details of our legal proceedings in Note 12. Some of this

" available supply resources, information is about costs that may be material to our financial

" transportation and transmission availability and results.

reliability within and between regions, 35

Accounting Standards Adopted and Issued to mark-to-market accounting. Contracts that are eligible for We discuss recently adopted and issued accounting standards in accrual accounting include non-derivative transactions and Note 1. derivatives that qualify for and are designated as normal purchases and normal sales of commodities that will be Critical Accounting Policies physically delivered.

Our discussion and analysis of financial condition and results of The use of accrual accounting requires us to analyze operations is based on our consolidated financial statements that contracts to determine whether they are non-derivatives or, if were prepared in accordance with accounting principles generally they are derivatives, whether they meet the requirements for accepted in the United States of America. Management makes designation as normal purchases and normal sales. For those estimates and assumptions when preparing financial statements. contracts that do not meet these criteria, we may also analyze These estimates and assumptions affect various matters, whether they qualify for hedge accounting, including performing including: an evaluation of historical market price information to determine

" our reported amounts of revenues and expenses in our whether such contracts are expected to be highly effective in Consolidated Statements of Income, offsetting changes in cash flows from the risk being hedged. We

• our reported amounts of assets and liabilities in our record the fair value of derivatives for which we have elected Consolidated Balance Sheets, and hedge accounting in "Risk management assets and liabilities."

" our disclosure of contingent assets and liabilities. We use the mark-to-market method of accounting for These estimates involve judgments with respect to derivative contracts for which we are not permitted to use numerous factors that are difficult to predict and are beyond accrual accounting or hedge accounting. These mark-to-market management's control. As a result, actual amounts could activities include derivative contracts for energy and other materially differ from these estimates. energy-related commodities. Under the mark-to-market method Management believes the following accounting policies of accounting, we record the fair value of these derivatives as represent critical accounting policies as defined by the Securities mark-to-market energy assets and liabilities at the time of and Exchange Commission (SEC). The SEC defines critical contract execution. We record the changes in mark-to-market accounting policies as those that are both most important to the energy assets and liabilities in our Consolidated Statements of portrayal of a company's financial condition and results of Income.

operations and require management's most difficult, subjective, Mark-to-market energy assets and liabilities consist of a or complex judgment, often as a result of the need to make combination of energy and energy-related derivative contracts.

estimates about the effect of matters that are inherently While some of these contracts represent commodities or uncertain and may change in subsequent periods. We discuss our instruments for which prices are available from external sources, significant accounting policies, including those that do not other commodities and certain contracts are not actively traded require management to make difficult, subjective, or complex and are valued using modeling techniques to determine expected judgments or estimates, in Note 1. future market prices, contract quantities, or both. The market prices and quantities used to determine fair value reflect Accounting for Derivatives management's best estimate considering various factors. However, Our merchant energy business originates and acquires contracts future market prices and actual quantities will vary from those for energy, other energy-related commodities, and related used in recording mark-to-market energy assets and liabilities, derivatives. We record merchant energy business revenues using and it is possible that such variations could be material.

two methods of accounting: accrual accounting and We record valuation adjustments to reflect uncertainties mark-to-market accounting. The accounting requirements for associated with certain estimates inherent in the determination derivatives are governed by Statement of Financial Accounting of the fair value of mark-to-market energy assets and liabilities.

Standard (SFAS) No. 133, Accountingfor DerivativeInstruments The effect of these uncertainties is not incorporated in market and Hedging Activities, as amended, and applying those price information or other market-based estimates used to requirements involves the exercise of judgment in evaluating determine fair value of our mark-to-market energy contracts. To these provisions, as well as related implementation guidance and the extent possible, we utilize market-based data together with applying those requirements to complex contracts in a variety of quantitative methods for both measuring the uncertainties for commodities and markets. which we record valuation adjustments and determining the level We record revenues and fuel and purchased energy expenses of such adjustments and changes in those levels.

from the sale or purchase of energy, energy-related products, and We describe on the next page the main types of valuation energy services under the accrual method of accounting in the adjustments we record and the process for establishing each.

period when we deliver or receive energy commodities, products, Generally, increases in valuation adjustments reduce our and services, or settle contracts. We use accrual accounting for earnings, and decreases in valuation adjustments increase our our merchant energy and other nonregulated business earnings. However, all or a portion of the effect on earnings of transactions, including the generation or purchase and sale of changes in valuation adjustments may be offset by changes in electricity, gas, and coal as part of our physical delivery activities the value of the underlying positions.

and for power, gas, and coal sales contracts that are not subject 36

• Close-out adjustment-represents the estimated cost to and could affect us either favorably or unfavorably. We discuss dose out or sell to a third-party open mark-to-marker our market risk in more derail in the Market Risk section.

positions. This valuation adjustment has the effect of The impact of derivative contracts on our revenues and valuing "long" positions (the purchase of a commodity) costs is affected by many factors, including:

at the bid price and "short" positions (the sale of a

• our ability to designate and qualify derivative contracts commodity) at the offer price. We compute this for normal purchase and sale accounting or hedge adjustment using a market-based estimate of the bid/ accounting under SIAS No. 133, offer spread for each commodity and option price and " potential volatility in earnings from ineffectiveness the absolute quantity of our net open positions for each associated with derivatives subject to hedge accounting, year. The level of total close-out valuation adjustments " potential volatility in earnings from derivative contracts increases as we have larger unhedged positions, bid-offer that serve as economic hedges but do not meet the spreads increase, or market information is not available, accounting requirements to qualify for normal purchase and it decreases as we reduce our unhedged positions, and normal sale accounting or hedge accounting, bid-offer spreads decrease, or market information " our ability to enter into new mark-to-market derivative becomes available. To the extent that we are not able to origination transactions, and obtain observable market information for similar " sufficient liquidity and transparency in the energy contracts, the dose-out adjustment is equivalent to the markets to permit us to record gains at inception of new initial contract margin, thereby resulting in no gain or derivative contracts because fair value is evidenced by loss at inception. In the absence of observable market quoted market prices, current market transactions, or information, there is a presumption that the transaction other observable market information.

price is equal to the market value of the contract, and therefore we do not recognize a gain or loss at Evaluation of Assets for Impairment and Other Than inception. We recognize such gains or losses in earnings Temporary Decline In Value as we realize cash flows under the contract or when Long-Lived Assets observable market data becomes available. We are required to evaluate certain assets that have long lives

• Credit-spread adjustment-for risk management (for example, generating property and equipment and real estate) purposes, we compute the value of our mark-to-market to determine if they are impaired when certain conditions exist.

energy assets and liabilities using a risk-free discount SFAS No. 144, Accounting for the Impairmentor Disposalof rate. In order to compute fair value for financial Long-LivedAssets, provides the accounting requirements for reporting purposes, we adjust the value of our impairments of long-lived assets. We are required to test our mark-to-market energy assets to reflect the credit- long-lived assets for recoverability whenever events or changes in worthiness of each counterparty based upon either circumstances indicate that their carrying amount may not be published credit ratings, or equivalent internal credit recoverable. Examples of such events or changes are:

ratings and associated default probability percentages. " a significant decrease in the market price of a long-lived We compute this adjustment by applying a default asset, probability percentage to our outstanding credit " a significant adverse change in the manner an asset is exposure, net of collateral, for each counterparty. The being used or its physical condition, level of this adjustment increases as our credit exposure " an adverse action by a regulator or legislation or in the to counterparties increases, the maturity terms of our business climate, transactions increase, or the credit ratings of our " an accumulation of costs significantly in excess of the counterparties deteriorate, and it decreases when our amount originally expected for the construction or credit exposure to counterparties decreases, the maturity acquisition of an asset, terms of our transactions decrease, or the credit ratings " a current-period loss combined with a history of losses of our counterparties improve. or the projection of future losses, or Market prices for energy and energy-related commodities " a change in our intent about an asset from an intent to vary based upon a number of factors, and changes in market hold to a greater than 50% likelihood that an asset will prices affect both the recorded fair value of our mark-to-market be sold or disposed of before the end of its previously energy contracts and the level of future revenues and costs estimated useful life.

associated with accrual-basis activities. Changes in the value of For long-lived assets that are expected to be held and used, our mark-to-market energy contracts will affect our earnings in SFAS No. 144 provides that an impairment loss shall only be the period of the change, while changes in forward market prices recognized if the carrying amount of an asset is not recoverable related to accrual-basis revenues and costs will affect our earnings and exceeds its fair value. The carrying amount of an asset is in future periods to the extent those prices are realized. We not recoverable under SFAS No. 144 if the carrying amount cannot predict whether, or to what extent, the factors affecting exceeds the sum of the undiscounted future cash flows expected market prices may change, but those changes could be material to result from the use and eventual disposition of the asset.

Therefore, when we believe an impairment condition may have 37

occurred, we are required to estimate the undiscounted future The evaluation and measurement of impairments under the cash flows associated with a long-lived asset or group of APB No. 18 standard involves the same uncertainties as long-lived assets. This necessarily requires us to estimate described on the previous page for long-lived assets that we own uncertain future cash flows. directly and account for in accordance with SFAS No. 144.

In order to estimate an assetes future cash flows, we Similarly, the estimates that we make with respect to our equity consider historical cash flows and changes in the market and cost-method investments are subject to variation, and the environment and other factors that may affect future cash flows. impact of such variations could be material. Additionally, if the To the extent applicable, the assumptions we use are consistent projects in which we hold these investments recognize an with forecasts that we are otherwise required to make (for impairment under the provisions of SFAS No. 144, we would example, in preparing our other earnings forecasts). If we are record our proportionate share of that impairment loss and considering alternative courses of action to recover the carrying would evaluate our investment for an other than temporary amount of a long-lived asset (such as the potential sale of an decline in value under APB No. 18.

asset), we probability-weight the alternative courses of action to estimate the cash flows. Gas Properties We use our best estimates in making these evaluations and We evaluate unproved property at least annually to determine if consider various factors, including forward price curves for it is impaired under SFAS No. 19, FinancialAccounting and energy, fuel costs, and operating costs. However, actual future Reporting by Oil and Gas Producing Properties.Impairment for market prices and project costs could vary from the assumptions unproved property occurs if there are no firm plans to continue used in our estimates, and the impact of such variations could drilling, lease expiration is at risk, or historical experience be material. necessitates a valuation allowance.

For long-lived assets that can be classified as assets held for sale under SFAS No. 144, an impairment loss is recognized to Debt and Equity Securities the extent their carrying amount exceeds their fair value less Our investments in debt and equity securities, primarily our costs to sell. nuclear decommissioning trust fund assets, are subject to If we determine that the undiscounted cash flows from an impairment evaluations under FASB Staff Position SIAS 115-1 asset to be held and used are less than the carrying amount of and SFAS 124-1 (FSP 115-1 and 124-1), The Meaning of the asset, or if we have classified an asset as held for sale, we Other-Than-TemporaryImpairment and Its Application to Certain must estimate fair value to determine the amount of any Investments. FSP 115-1 and 124-1 requires us to determine impairment loss. The estimation of fair value under SFAS whether a decline in fair value of an investment below the No. 144, whether in conjunction with an asset to be held and amortized cost basis is other than temporary. If we determine used or with an asset held for sale, also involves judgment. We that the decline in fair value is judged to be other than consider quoted market prices in active markets to the extent temporary, the cost basis of the investment must be written they are available. In the absence of such information, we may down to fair value as a new cost basis.

consider prices of similar assets, consult with brokers, or employ other valuation techniques. Often, we will discount the Goodwill estimated future cash flows associated with the asset using a Goodwill is the excess of the purchase price of an acquired single interest rate that is commensurate with the risk involved business over the fair value of the net assets acquired. We with such an investment or employ an expected present value account for goodwill and other intangibles under the provisions method that probability-weights a range of possible outcomes. of SFAS No. 142, Goodwill and OtherIntangibleAssets. We do The use of these methods involves the same inherent uncertainty not amortize goodwill and certain other intangible assets. SFAS of future cash flows as discussed above with respect to No. 142 requires us to evaluate goodwill for impairment at least undiscounted cash flows. Actual future market prices and project annually or more frequently if events and circumstances indicate costs could vary from those used in our estimates, and the the business might be impaired. Goodwill is impaired if the impact of such variations could be material. carrying value of the business exceeds fair value. Annually, we We are also required to evaluate our equity-method and estimate the fair value of the businesses we have acquired using cost-method investments (for example, in partnerships that own techniques similar to those used to estimate future cash flows for power projects) to determine whether or not they are impaired. long-lived assets as discussed on the previous page, which Accounting Principles Board Opinion (APB) No. 18, The Equity involves judgment. If the estimated fair value of the business is Method ofAccounting for Investments in Common Stock, provides less than its carrying value, an impairment loss is required to be the accounting requirements for these investments. The standard recognized to the extent that the carrying value of goodwill is for determining whether an impairment must be recorded under greater than its fair value.

APB No. 18 is whether the investment has experienced a loss in value that is considered an "other than a temporary" decline in value.

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Asset Retirement Obligations Commodity Prices We incur legal obligations associated with the retirement of During 2005, the energy markets were affected by higher certain long-lived assets. SFAS No. 143, Accountingfor Asset commodity prices caused by a tight supply and demand balance, Retirement Obligations, provides the accounting for legal the impact of hot weather, and hurricane-related supply obligations associated with the retirement of long-lived assets. disruptions in the Gulf Coast. These events contributed to the We incur such legal obligations as a result of environmental and following changes in our financial statements:

other government regulations, contractual agreements, and other

• total mark-to-market assets increased $1,501.4 million factors. The application of this standard requires significant and total mark-to-market liabilities increased judgment due to the large number and diverse nature of the $1,386.3 million since December 31, 2004, assets in our various businesses and the estimation of future cash " total risk management assets increased $1,092.6 million flows required to measure legal obligations associated with the and total risk management liabilities increased retirement of specific assets. FASB Interpretation (FIN) 47, $742.5 million since December 31, 2004, Accountingfor ConditionalAsset Retirement Obligations-an

• customer deposits and collateral increased interpretationofFASB Statement No. 143, clarifies that $235.1 million since December 31, 2004, obligations that are conditional upon a future event are subject " accumulated other comprehensive income decreased to the provisions of SFAS No. 143. $314.0 million since December 31, 2004, SFAS No. 143 requires the use of an expected present value " total revenues increased $4,845.6 million during 2005 methodology in measuring asset retirement obligations that compared to 2004, and involves judgment surrounding the inherent uncertainty of the " total fuel and purchased energy expenses increased probability, amount and timing of payments to settle these $4,546.8 million during 2005 compared to the same obligations, and the appropriate interest rates to discount future period of 2004.

cash flows. We use our best estimates in identifying and We discuss the impact of higher commodity prices on our measuring our asset retirement obligations in accordance with financial condition and results of operations in more detail in SFAS No. 143. the following sections:

Our nuclear decommissioning costs represent our largest " Merchant Energy Results, asset retirement obligation. This obligation primarily results from " FinancialCondition, the requirement to decommission and decontaminate our " ContractualPayment Obligationsand Committed nudear generating facilities in connection with their future Amounts, and retirement. We utilize site-specific decommissioning cost " Market Risk.

estimates to determine our nuclear asset retirement obligations.

However, given the magnitude of the amounts involved, Discontinued Operations complicated and ever-changing technical and regulatory In June 2005, we sold our Oleander generating facility and in requirements, and the very long time horizons involved, the October 2005, we sold Constellation Power International actual obligation could vary from the assumptions used in our Investments, Ltd., which held our other nonregulated estimates, and the impact of such variations could be material. international investments. Our other nonregulated international investments included our interests in a Panamanian electric Significant Events distribution facility and a fund that holds interests in two South Pending Merger with FPL Group, Inc. American energy projects.

On December 18, 2005, Constellation Energy entered into an We discuss the sale of the Oleander generating facility and Agreement and Plan of Merger with FPL Group, Inc. We our other nonregulated international investments in more detail discuss the details of this pending merger in Note 15. in the Note 2.

Prior to the merger, which is subject to shareholder and various regulatory approvals, Constellation Energy and FPL Business Combination and Asset Acquisition Group will continue to operate as separate companies. The In April 2005, we acquired Cogenex Corporation and in discussion and analysis of our results of operations and financial June 2005, we acquired working interests in gas producing fields condition beginning on the next page relates solely to in Texas and Alabama.

Constellation Energy. We discuss these transactions in more detail in Note 15.

Dividend Increase In January 2006, we announced an increase in our quarterly dividend to $0.3775 per share on our common stock. This is equivalent to an annual rate of $1.51 per share. Previously, our quarterly dividend on our common stock was $0.335 per share, equivalent to an annual rate of $1.34 per share.

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Results of Operations " We recorded higher income from discontinued In this section, we discuss our earnings and the factors affecting operations of $50.7 million after-tax. In 2005, we them. We begin with a general overview, then separately discuss recorded in "Income (loss) from discontinued earnings for our operating segments. Significant changes in other operations" earnings of $23.6 million related to the sale income and expense, fixed charges, and income taxes are of our Oleander generating facility and our other discussed in the aggregate for all segments in the Consolidated nonregulated international investments. In 2004, we Nonoperating Income and Expenses section. recorded in "Income (loss) from discontinued operations" a loss of $49.1 million after tax related to Overview the sale of our Hawaiian geothermal facility which had a Results negative impact in that period. The loss was offset by 2005 2004 2003 the reclassification of earnings of $22.0 million after-tax (In millions, after-tax) from our Oleander and international operations to Merchant energy $430.2 $426.4 $301.1 "Income (loss) from discontinued operations." We Regulated electric 149.4 131.1 107.5 discuss the sale of these operations in more detail in Regulated gas 26.7 22.2 43.0 Note 2.

Other nonregulated 0.4 (12.9) 5.1 " We had higher earnings of $32.7 million after-tax Income from continuing operations and primarily due to higher interest and investment income before cumulative effects of changes in due to a higher cash balance, and higher accounting principles 606.7 566.8 456.7 decommissioning trust asset earnings, and lower interest Income (loss) from discontinued expense resulting from the maturity of $300.0 million operations 23.6 (27.1) 19.0 in long-term debt in 2005 and the favorable impact of Cumulative effects of changes in floating-rate swaps.

accounting principles (7.2) - (198.4)

" We had higher earnings of $29.1 million after-tax at our Net Income $623.1 $539.7 $277.3 Nine Mile Point and Ginna facilities primarily due to Other Items Included in Operations: productivity improvements and cost saving initiatives Non-qualifying hedges $ (24.9) $ 0.2 $ (28.7) partially offset by inflationary cost increases and costs Merger-related transaction costs (15.6) - - associated with the planned refueling outage at Ginna.

Workforce reduction costs (2.6) (5.9) (1.3)

• We had higher earnings of $22.8 million after-tax at our Recognition of 2003 synthetic fuel tax regulated businesses primarily due to favorable weather credits - 35.9 -

during 2005 compared to 2004.

Total Other Items $ (43.1) $ 30.2 $ (30.0)

• We had higher earnings of approximately $17 million after-tax due to the absence of coal delivery issues that 2005 were experienced in 2004 that had a negative impact in Our total net income for 2005 increased $83.4 million, or $0.35 that period. We discuss the coal delivery issues in more per share, compared to the same period of 2004 mostly because detail in the Business Environment-OtherFactors of the following: section.

• We had higher earnings of approximately $58 million at " We had higher earnings from our other nonregulated our wholesale marketing and risk management businesses of $13.3 million after-tax, including higher operation. This increase is primarily due to the gains from the continued liquidation of our non-core realization of higher gross margin, which included the investments and the results of Cogenex, which was termination or restructuring of several energy contracts acquired in April 2005. We discuss the acquisition of and higher mark-to-market results in earnings. We Cogenex in more detail in Note 15.

discuss these terminations, restructurings, and " We had higher earnings at our South Carolina synthetic mark-to-market results in more detail in the Competitive fuel facility of $7.6 million after-tax due to a higher Supply section. This increase in earnings was partially level of production in 2005 compared to 2004.

offset by higher load-serving costs resulting from These increases were partially offset by the following:

extreme weather and volatile commodity prices and " Our merchant energy business recognized $35.9 million higher operating expenses. of 2003 synthetic fuel tax credits in 2004 which had a positive impact in that period.

• We had lower earnings at our retail competitive supply operation of $25.1 million after-tax primarily due to higher costs to serve our load obligations in Texas and the absence of bankruptcy settlements that had a favorable impact in 2004.

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" We had lower earnings of $25.1 million after-tax related

• We had higher earnings due to lower after-tax losses of to losses associated with certain economic hedges that $28.9 million associated with certain economic hedges do not qualify for cash-flow hedge accounting that do not qualify for cash-flow hedge accounting treatment. We discuss these economic hedges in more treatment. We discuss these economic hedges in more detail in the Mark-to-Marketsection. detail in the Mark-to-Market section.

" We had lower earnings of $15.6 million after-tax due to " We had higher earnings of $20.9 million after-tax in external costs associated with the execution of our 2004 due to a full year of operations at the High Desert merger agreement with FPL Group. facility.

" We had lower earnings of $20.0 million after-tax due to These increases were partially offset by the following:

lower CTC revenues at our merchant energy business.

• We recorded a $49.1 million after-tax, loss from

" We had lower earnings of $8.5 million after-tax related discontinued operations on the sale of our Hawaiian to the impact of expensing stock options during the geothermal facility.

fourth quarter of 2005. " We had higher Sarbanes-Oxley 404 implementation

" We had lower earnings of $7.2 million after-tax due to costs of approximately $15 million pre-tax, higher the cumulative effect of adopting FIN 47 and SFAS enterprise information systems expenditures of No. 123 Revised (SFAS No. 123R), Share-Based approximately $8 million pre-tax, and higher Payment. We discuss the adoption of these standards in compensation, benefit, and other inflationary cost detail in Note 1. increases.

Earnings per share was impacted by additional dilution,

• We had lower earnings from our regulated gas business including the issuance of 6.0 million shares of common stock on mostly because of $13.6 million after-tax of higher July 1, 2004. operations and maintenance expenses in 2004 and the absence of a $4.7 million after-tax market-based rate gas 2004 recovery, which had a favorable effect in 2003.

Our total net income for 2004 increased $262.4 million, or " We recognized a gain of $16.4 million after-tax related

$1.46 per share, compared to the same period of 2003 mostly to non-core asset sales in 2003 that had a favorable because of the following: impact in that period.

• In 2003, we recorded a $266.1 million after-tax loss for Earnings per share was impacted by additional dilution the cumulative effect of adopting Emerging Issues Task resulting from the issuance of 6.0 million shares of common Force (EITF) Issue 02-3, Issues Involved in Accounting for stock on July 1, 2004.

Derivative Contracts Heldfor Trading Purposes and ContractsInvolved in Energy Tradingand Risk Merchant Energy Business ManagementActivities. This was partially offset by a Background

$67.7 million after-tax gain for the cumulative effect of Our merchant energy business is a competitive provider of adopting SFAS No. 143. These items had a combined energy solutions for various customers. We discuss the impact of negative impact during 2003. deregulation on our merchant energy business in Item 1.

" Our merchant energy business had higher earnings of Business--Competition section.

$78.4 million at our South Carolina synthetic fuel Our merchant energy business focuses on delivery of facility primarily due to the recognition of $35.9 million physical, customer-oriented products to producers and in tax credits associated with 2003 production and tax consumers, manages the risk and optimizes the value of our credits associated with 2004 production. owned generation assets, and uses our portfolio management and

" We had higher earnings from our regulated electric trading capabilities both to manage risk and to deploy risk business mostly because of the absence of $19.4 million capital to generate additional returns.

of after-tax incremental operations and maintenance We record merchant energy revenues and expenses in our expenses due to distribution service restoration efforts financial results in different periods depending upon which associated with Hurricane Isabel in 2003. portion of our business they affect. We discuss our revenue

" We had higher earnings from our nuclear generating recognition policies in the CriticalAccounting Policies section and assets due to the June 2004 acquisition of Ginna, which in Note 1. We summarize our revenue and expense recognition contributed $28.1 million after-tax, and higher policies as follows:

generation at our Calvert Cliffs nuclear power plant,

• We record revenues as they are earned and fuel and partially offset by lower generation by and lower power purchased energy expenses as they are incurred for prices for the output of our Nine Mile Point facility in contracts and activities subject to accrual accounting, 2004 compared to 2003. including certain load-serving activities.

• We had higher- earnings from our merchant energy business mostly due to the realization of wholesale contracts originated in prior periods, portfolio management, and favorable settlements at our retail electric operation of $16.9 million pre-tax.

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• Prior to the settlement of the forecasted transaction Results being hedged, we record changes in the fair value of 2005 2004 2003 contracts designated as cash-flow hedges in other (In millions) comprehensive income to the extent that the hedges are Revenues $14,786.1 $10,347.5 $ 7,587.5 effective. We record the effective portion of the changes Fuel and purchased energy expenses (12,308.9) (8,124.8) (5,702.2) in fair value of hedges in earnings in the period the Operating expenses (1.364.3) (1,172.8) (932.8)

Merger-related transaction costs (11.2) - -

settlement of the hedged transaction occurs. We record Workforce reduction costs (4.4) (9.7) (1.2) the ineffective portion of the changes in fair value of Depreciation, depletion, and hedges, if any, in earnings in the period in which the amortization (269.6) (239.2) (214.6) change occurs. Accretion of asset retirement

" We record changes in the fair value of contracts that are obligations (62.1) (53.2) (42.7) subject to mark-to-market accounting in revenues or fuel Taxes other than income taxes (112.2) (88.5) (85.9) and purchased energy expenses in the period in which Income from Operations $ 653.4 $ 659.3 $ 608.1 the change occurs.

Income from continuing operations Mark-to-market accounting requires us to make estimates and before cumulative effects of and assumptions using judgment in determining the fair value of changes in accounting principles certain contracts and in recording revenues from those contracts. (after-tax) $ 430.2 $ 426.4 $ 301.1 We discuss the effects of mark-to-market accounting on our Income (loss) from discontinued results in the Competitive Supply[-Mark-to-Market section. We operations (after-tax) 3.0 (36.5) 11.9 discuss mark-to-market accounting and the accounting policies Cumulative effects of changes in for the merchant energy business further in the Critical accounting principles (after-tax) (7.4) - (198.4)

Accounting Policies section and in Note 1. Net Income $ 425.8 $ 389.9 $ 114.6 Our wholesale marketing and risk management operation Other Items Included in Operations actively uses energy and energy-related commodities in order to (afier-tax) manage our portfolio of energy purchases and sales to customers Non-qualifying hedges $ (24.9) $ 0.2 $ (28.7) through structured transactions. As part of our risk management Merger-related transaction costs (10.4) - -

activities we trade energy and energy-related commodities and Workforce reduction costs (2.6) (5.9) (0.7) deploy risk capital in the management of our portfolio in order Recognition of 2003 synthetic to earn additional returns. These activities are managed through fuel tax credits - 35.9 daily value at risk and stop loss limits and liquidity guidelines, Total Other Items $ (37.9) $ 30.2 $ (29.4) and may have a material impact on our financial results. We Certain prior-yearamounts have been reclassifiedto conform with the current discuss the impact of our trading activities and value at risk in year's presentation.

more derail in the Competitive Supply-Mark-to-Market and Above amounts include intercompany transactionseliminatedin our Market Risk sections.

ConsolidatedFinancialStatements. Note 3 provides a reconciliationof operating results by segment to our ConsolidatedFinancialStatements.

Revenues and Fuel andPurchasedEnergy Etpenses Our merchant energy business manages the revenues we realize from the sale of energy to our customers and our costs of procuring fuel and energy. The difference between revenues and fuel and purchased energy expenses is the gross margin of our merchant energy business, and this measure is a useful tool for assessing the profitability of our merchant energy business.

Accordingly, we believe it is appropriate to discuss the operating results of our merchant energy business by analyzing the changes in gross margin between periods. In managing our portfolio, we may terminate, restructure, or acquire contracts. Such transactions are within the normal course of managing our portfolio and may materially impact the timing of our recognition of revenues, fuel and purchased energy expenses, and cash flows.

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We analyze our merchant energy gross margin in the We provide a summary of our revenues, fuel and purchased following categories because of the risk profile of each category, energy expenses, and gross margin as follows:

differences in the revenue sources, and the nature of fuel and 2005 2004 2003 purchased energy expenses. With the exception of a portion of (Dollaramounts in millions) our competitive supply activities that we are required to account Revenues:

for using the mark-to-market method of accounting, all of these Mid-Adantic Region $ 2,283.9 $ 1,925.6 S 1,696.2 activities are accounted for on an accrual basis. Plants with Power Purchase Agreements 829.6 714.5 574.6

" Mid-Atlantic Region-our fossil, nuclear, and Competitive Supply hydroelectric generating facilities and load-serving Retail 6,942.3 4,280.0 2,567.7 activities in the PJM Interconnection (PJM) region. Wholesale 4,672.3 3,353.8 2,703.9 This also includes active portfolio management of the Other 58.0 73.6 45.1 generating assets and other physical and financial Total $ 14,786.1 $10,347.5 $ 7,587.5 contractual arrangements, as well as other PJM Fuel and purchased energy competitive supply activities. expenses:

• Plants with Power Purchase Agreements-our generating Mid-Atlantic Region S (1,436.5) S (946.9) $ (711.6)

Plants with Power facilities outside the Mid-Atlantic Region with long-term Purchase Agreements (79.6) (53.1) (48.0) power purchase agreements, including the Nine Mile Competitive Supply Point, Ginna, University Park, and High Desert Retail (6,668.2) (4,011.4) (2,389.5) generating facilities. Wholesale (4,124.6) (3,113.4) (2,553.1)

Other - - -

• Wholesale Competitive Supply-our marketing and risk management operation that provides energy products Total $(12,308.9) $ (8,124.8) $(5,702.2) and services (including portfolio management and  % of  % of  % of trading activities) outside the Mid-Atlantic Region Gross margin: Tt Total primarily to distribution utilities, power generators, and Mid-Atlantic Region $ 847.4 34% $ 978.7 44% $ 984.6 52%

other wholesale customers. We also provide global coal Plants with Power Purchase Agreements 750.0 30 661.4 30 526.6 28 and upstream and downstream natural gas services. Competitive Supply

" Retail Competitive Supply-our operation that provides Retail 274.1 11 268.6 12 178.2 9 electric and gas energy products and services to Wholesale 547.7 22 240.4 11 150.8 8 commercial, industrial and governmental customers. Other 58.0 3 73.6 3 45.1 3

" Other-our investments in qualifying facilities and Total $ 2,477.2 100% $ 2.222.7 100% $ 1,885.3 100%

domestic power projects and our generation operations Ortainprior-year amounts have been reclassified to confirm with the currntyear's and maintenance services. presentation.

Mid-Atlantic Region 2005 2004 2003 (In millions)

Revenues $ 2,283.9 $1,925.6 $1,696.2 Fuel and purchased energy expenses (1,436.5) (946.9) (711.6)

Gross margin $ 847.4 $ 978.7 $ 984.6 The decrease in Mid-Atlantic Region gross margin in 2005 compared to 2004 is primarily due to rising commodity prices and hotter than normal weather during the third quarter of 2005, which resulted in higher load-serving costs. In addition, CTC revenues were $33.1 million lower during 2005 compared to the same period of 2004. These decreases in gross margin were partially offset by the absence of coal delivery issues that we experienced in 2004 that had a negative impact in that period. We discuss the coal delivery issues in the Business Environment-OtherFactorssection.

CFC revenues will continue to decrease as residential, commercial, and industrial customers complete their CTC obligation. CTC revenues will be completely phased-out for residential customers by June 30, 2006 and CTC revenues for commercial and industrial customers will begin to be phased-out after June 30, 2006. We discuss the change in CTC revenue over time in more detail in Item 1. Business.

43

The slight decrease in Mid-Atlantic Region gross margin in Competitive Supply 2004 compared to 2003 is primarily due to lower fossil plant Retail availability resulting in lower gross margin of $17.0 million and higher coal costs primarily due to purchasing coal from 2005 2004 2003 alternative suppliers in 2004 at higher prices than in 2003 as a (In millions) result of delays in deliveries. These decreases were partially offset Accrual revenues $ 6,944.2 $ 4,281.0 $ 2,567.7 Mark-to-market results recorded by an increase in margin of $7.1 million related to new in earnings 18.3 (1.0) -

load-serving obligations, offset in part by lower volumes served Fuel and purchased energy to BGE resulting from small commercial customers leaving expenses (6,688.4) (4,011.4) (2.389.5)

BGE's standard offer service due to the end of fixed-price service Gross margin $ 274.1 $ 268.6 $ 178.2 in June 2004.

The slight increase in gross margin from our retail competitive Plants with Power PurchaseAjereements supply activities in 2005 compared to 2004 is primarily due to serving approximately 20 million more megawatt hours in 2005 2005 2004 2003 compared to 2004 mostly due to the growth of this operation (In millions)

Revenues $829.6 $714.5 $574.6 and the positive impact of certain contracts that were recorded Fuel and purchased energy expenses (79.6) (53.1) (48.0) as mark-to-market. These increases were substantially offset by:

• a combination of higher market prices for electricity, Gross margin $750.0 $661.4 $526.6 price volatility, and increased customer usage primarily The increase in gross margin from our Plants with Power in Texas, which increased our cost to serve our Purchase Agreements in 2005 compared to 2004 was primarily load-serving obligations.

due to:

• the expiration of higher margin contracts, and

" higher gross margin of $71.5 million from Ginna,

• the absence of favorable bankruptcy settlements, which which was acquired in June 2004. This increase in gross had a positive impact in 2004. We discuss the favorable margin at Ginna includes an increase in revenues of bankruptcy settlements below.

$76.9 million. We discuss this acquisition in more detail The increase in gross margin from our retail competitive in Note 15, and supply activities in 2004 compared to 2003 is primarily due to

" higher gross margin of $39.0 million at our Nine Mile higher electric gross margin of $66.1 million mostly due to:

Point facility that benefited from higher generation " serving approximately 16 million more megawatt hours primarily due to fewer refueling outage days, the partially offset by lower realized margins due to absence of an unplanned outage that occurred in increased wholesale power costs in 2004 compared to January 2004, and higher prices on the portion of our 2003, output sold into the wholesale market. " a bankruptcy settlement from PG&E of $10.3 million These increases in gross margin were partially offset by in 2004, and a favorable settlement of a pre-acquisition

$21.9 million primarily related to changes in commodity prices liability of $6.6 million also related to a bankruptcy that had a negative impact on realized hedging activities related proceeding in 2004, and to the portion of these facilities sold into the wholesale market. " lower contract amortization, which reduced margin by The increase in gross margin from our Plants with Power $9.2 million, relating to the fair value of contracts Purchase Agreements in 2004 compared to 2003 is primarily acquired.

due to: In addition, we had higher gas gross margin contribution of

• gross margin of $112.4 million from Ginna. The $17.1 million from Blackhawk Energy Services and Kaztex increase in gross margin includes higher revenues of Energy Management, which were acquired in October 2003. We

$119.1 million, and discuss our acquisitions in more derail in Note I5.

• higher gross margin of $45.9 million from the High Desert facility that contributed a full year of gross Wholesale margin in 2004 compared to eight months in 2003. 2005 2004 2003 These increases in gross margin were partially offset by (In millions) lower gross margin of $21.0 million at our Nine Mile Point Accrual revenues $ 4,281.8 $ 3,253.7 $ 2,667.7 facility primarily due to lower revenues from reduced contract Fuel and purchased energy prices for the output in 2004 compared to 2003 and lower expenses (4,124.6) (3,113.4) (2,553.1) generation. Wholesale accrual activities 157.2 140.3 114.6 Mark-to-market results recorded in earnings 390.5 100.1 36.2 Gross margin $ 547.7 $ 240.4 $ 150.8 We analyze our wholesale accrual and mark-to-market competitive supply activities separately on the next page.

44

Wholesale Accrual Activities Mark-to-market results recorded in earnings were as follows:

Our wholesale marketing and risk management operation's 2005 2004 2003 accrual gross margin was $16.9 million higher in 2005 (In millions) compared to 2004 primarily due to newly originated and Unrealized mark-to-market results realized business in power, gas, and coal in 2005, including recorded in earnings several contract terminations and restructurings. During 2005, Origination gains $ 61.6 $ 19.7 $ 62.3 we terminated or restructured several in-the-money contracts in Risk management and trading Unrealized changes in fir value 347.2 79.4 (26.1) exchange for upfront cash payments and a reduction or Changes in valuation techniques - - -

cancellation of future performance obligations. The termination Redassification of settled contracts or restructuring of two contracts allowed us to lower our to realized (257.7) (85.4) (123.5) exposure to performance risk under these contracts, and resulted Total risk management and trading 89.5 (6.0) (149.6) in the realization of $77.0 million of pre-tax earnings in 2005 Total unrealized mark-to-market* 151.1 13.7 (87.3) that would have been recognized over the life of these contracts. Realized mark-to-market 257.7 85.4 123.5 These increases were partially offset by lower gross margins of Total mark-to-market results recorded in approximately $60 million mostly due to the absence of several earnings $ 408.8 $ 99.1 $ 36.2 favorable items, including settlements, power prices, and Total unrealizedmark-to-market is the sum of ortinationtransactionsand contracts that had a positive impact in 2004. total risk management and trading.

The increase in gross margin from our wholesale accrual Origination gains arise primarily from contracts that our activities in 2004 compared to 2003 is primarily due to wholesale marketing and risk management operation structures approximately $50 million in the New England region due to to meet the risk management needs of our customers.

higher realized contract margins in 2004 compared to 2003 and Transactions that result in origination gains may be unique and higher volumes served. This increase was partially offset by provide the potential for individually significant gains from a higher transportation costs for our gas trading portfolio of single transaction.

approximately $16 million. The transportation costs associated Origination gains represent the initial fair value recognized with this portfolio are accounted for on an accrual basis, while on these structured transactions. The recognition of origination our gas trading portfolio is recorded as mark-to-market. In gains is dependent on the existence of observable market data addition, we incurred higher operating costs of $5.0 million that validates the initial fair value of the contract. Origination related to our South Carolina synthetic fuel facility. gains arose primarily from:

• 6 transactions completed in 2005, one of which Mark-to-Market contributed approximately $35 million pre-tax, Mark-to-market results recorded in earnings include net gains

• 7 transactions completed in 2004, of which no and losses from origination, trading, and risk management transaction contributed in excess of $10 million pre-tax, activities for which we use the mark-to-market method of and accounting. We discuss these activities and the mark-to-market

• 14 transactions completed in 2003, of which one method of accounting in more detail in the CriticalAccounting transaction contributed approximately $10 million Policies section and in Note 1.

• pre-tax.

As a result of the nature of our operations and the use of As noted above, the recognition of origination gains is mark-to-market accounting for certain activities, mark-to-market dependent on sufficient observable market data. Liquidity and earnings will fluctuate. We cannot predict these fluctuations, but market conditions impact our ability to identify sufficient, the impact on our earnings could be material. We discuss our objective market-price information to permit recognition of market risk in more detail in the Market Risk section. The origination gains. As a result, while our strategy and competitive primary factors that cause fluctuations in our mark-to-market position provide the opportunity to continue to originate such results recorded in earnings are: - transactions, the level of origination gains we are able to

" the number, size, and profitability of new transactions recognize may vary from year to year as a result of the number, including terminations or restructuring of existing size, and market-price transparency of the individual transactions contracts, executed in any period.

" the number and size of our open derivative positions, Risk management and trading represents both realized and and unrealized gains and losses from changes in the value of our

• changes in the level and volatility of forward commodity portfolio, including the recognition of gains associated with prices and interest rates. decreases in the close-out adjustment when we are able to obtain sufficient market price information. We discuss the changes in mark-to-market results recorded in earnings on the next page.

We show the relationship between our mark-to-market results recorded in earnings and the change in our net mark-to-market energy asset later on the next page.

45

Mark-to-marker results recorded in earnings increased Mark-to-Market Energy Assets and Liabilities

$309.7 million in 2005 compared to 2004 due to: Our mark-to-market energy assets and liabilities are comprised of

• approximately $260 million primarily related to a higher derivative contracts. While some of our mark-to-market contracts level of risk management and trading activities. Increases represent commodities or instruments for which prices are in our gas and coal activities, higher commodity price available from external sources, other commodities and certain volatility, and greater market liquidity resulted in more contracts are not actively traded and are valued using other opportunities to deploy risk capital and to earn pricing sources and modeling techniques to determine expected additional returns in 2005 compared to 2004. These future market prices, contract quantities, or both. We discuss our items resulted in an increased number of transactions modeling techniques later in this section.

that were entered into and realized during 2005 and a Mark-to-market energy assets and liabilities consisted of the higher level of open positions that resulted in increased following:

gains in 2005 compared to 2004. During 2005, slightly more than half of the mark-to-market results were At December 31, 2005 2004 derived from power, approximately one-third from gas, (In millions) and the remainder from other transactions. Current Assets $1,339.2 $567.3

• $41.9 million related to a higher level of origination Noncurrent Assets 1,089.3 359.8 gains as discussed on the previous page, and Total Assets 2,428.5 927.1

• $49.9 million related to the decrease in the dose-out Current Liabilities 1,348.7 559.7 adjustment during 2005 compared to the prior year for Noncurrent Liabilities 912.3 315.0 transactions that we have now observed sufficient market price information and/or we realized cash flows since the Total Liabilities 2,261.0 874.7 transactions' inception. Net mark-to-market energy asset $ 167.5 $ 52.4 These increases in mark-to-market results recorded in The following are the primary sources of the change in net earnings were partially offset by the impact of $41.5 million of mark-to-market energy asset during 2005 and 2004:

higher mark-to-market losses on certain economic hedges that did not qualify for cash-flow hedge accounting treatment. We 2005 2004 discuss these economic hedges in more detail below. (In millions)

Mark-to-market results recorded in earnings increased Fair value beginning of year $ 52.4 $ 18.8

$62.9 million in 2004 compared to 2003 mostly because of the Changes in fair value recorded in earnings impact of lower mark-to-market losses on economic hedges that Origination gains $ 61.6 $ 19.7 do not qualify for hedge accounting treatment as discussed in Unrealized changes in fair value 347.2 79.4 more detail below and lower losses from risk management and Changes in valuation techniques trading activities primarily due to favorable changes in regional Reclassification of settled contracts power prices, and price volatility. These increases were partially to realized (257.7) (85.4) offset by a lower level of origination gains in 2004 compared to Total changes in fair value recorded in 2003. The lower level of origination gains is primarily due to earnings 151.1 13.7 higher individually significant gains on contracts in 2003 that Contracts acquired 17.4 had a positive impact in that period. Changes in value of exchange-listed Changing forward prices result in shifting value between futures and options (119.9) (15.8) accrual contracts and the associated mark-to-market positions of Net change in premiums on options 79.7 29.4 certain contracts in New England that contain fuel adjustment Other changes in fair value (13.2) 6.3 clauses and gas transportation contract hedges, producing a Fair value at end of year $167.5 $ 52.4 timing difference in the recognition of earnings on these transactions. These mark-to-market hedges are economically Changes in the net mark-to-market energy asset that effective; however, they do not qualify for cash-flow hedge affected earnings were as follows:

accounting under SFAS No. 133. As a result, we recorded

• Origination gains represent the initial unrealized fair

$41.2 million of pre-tax losses in 2005, $0.3 million of pre-tax value at the time these contracts are executed to the gains in 2004, and pre-tax losses of $47.4 million in 2003. extent permitted by applicable accounting rules.

These mark-to-market gains and losses will be offset as we realize " Unrealized changes in fair value represent unrealized the related accrual load-serving positions in cash. changes in commodity prices, the volatility of options on commodities, the time value of options, and other valuation adjustments.

46

" Changes in valuation techniques represent improvements

• Changes in value of exchange-listed futures and options in estimation techniques, including modeling and other are adjustments to remove unrealized revenue from statistical enhancements used to value our portfolio to exchange-traded contracts that are included in risk reflect more accurately the economic value of our management revenues. The fair value of these contracts contracts. is recorded in "Accounts receivable" rather than

• Reclassification of settled contracts to realized represents "Mark-to-market energy assets" in our Consolidated the portion of previously unrealized amounts settled Balance Sheets because these amounts are settled during the period and recorded as realized revenues. through our margin account with a third-party broker.

The net mark-to-market energy asset also changed due to " Net changes in premiums on options reflects the the following items recorded in accounts other than in our accounting for premiums on options purchased as an Consolidated Statements of Income: increase in the net mark-to-market energy asset and

• Contracts acquired represents the initial fair value of premiums on options sold as a decrease in the net acquired derivative contracts recorded in "Mark-to- mark-to-market energy asset.

market energy assets."

The settlement terms of our net mark-to-market energy asset and sources of fair value as of December 31, 2005 are as follows:

Settlement Term 2006 2007 2008 2009 2010 2011 Thereafter Fair Value (In millioni)

Prices provided by external sources (1) $(12.6) $63.5 $81.8 $(2.7) $ (2.1) $ - $ - $127.9 Prices based on models 3.1 4.7 10.2 (0.6) 17.5 1.4 3.3 39.6 Total net mark-to-market energy asset $ (9.5) $68.2 $92.0 $(3.3) $15.4 $ 1.4 $3.3 $167.5 (1) Includes contracts actively quoted and contracts valued from other external sources.

We manage our mark-to-market risk on a portfolio basis The amounts for which fair value is determined using based upon the delivery period of our contracts and the prices provided by external sources represent the portion of individual components of the risks within each contract. forward, swap, and option contracts for which price quotations Accordingly, we record and manage the energy purchase and sale are available through brokers or over-the-counter transactions.

obligations under our contracts in separate components based The term for which such price information is available varies by upon the commodity (e.g., electricity or gas), the product (e.g., commodity, region, and product. The fair values included in this electricity for delivery during peak or off-peak hours), the category are the following portions of our contracts:

delivery location (e.g., by region), the risk profile (e.g., forward

• forward purchases and sales of electricity during peak or option), and the delivery period (e.g., by month and year). and off-peak hours for delivery terms primarily through Consistent with our risk management practices, we have 2008, but up to 2010, depending upon the region, presented the information in the table above based upon the " options for the purchase and sale of electricity during ability to obtain reliable prices for components of the risks in peak hours for delivery terms through 2008, depending our contracts from external sources rather than on a upon the region, contract-by-contract basis. Thus, the portion of long-term

• forward purchases and sales of electric capacity for contracts that is valued using external price sources is presented delivery terms primarily through 2007, but up to 2008, under the caption "prices provided by external sources."' This is depending on the region, consistent with how we manage our risk, and we believe it

• forward purchases and sales of natural gas, coal, and oil provides the best indication of the basis for the valuation of our for delivery terms through 2009, and portfolio. Since we manage our risk on a portfolio basis rather " options for the purchase and sale of natural gas, coal, than contract-by-contract, it is not practicable to determine and oil for delivery terms through 2008.

separately the portion of long-term contracts that is included in The remainder of the net mark-to-market energy asset is each valuation category. We describe the commodities, products, valued using models. The portion of contracts for which such and delivery periods included in each valuation category in detail techniques are used includes standard products for which below. external prices are not available and customized products that are valued using modeling techniques to determine expected future market prices, contract quantities, or both.

47

Modeling techniques include estimating the present value of Management uses its best estimates to determine the fair cash flows based upon underlying contractual terms and value of commodity and derivative contracts it holds and sells.

incorporate, where appropriate, option pricing models and These estimates consider various factors including dosing statistical and simulation procedures. Inputs to the models exchange and over-the-counter price quotations, time value, include: volatility factors, and credit exposure. However, future market

" observable market prices, prices and actual quantities will vary from those used in

" estimated market prices in the absence of quoted market recording mark-to-market energy assets and liabilities, and it is prices, possible that such variations could be material.

" the risk-free market discount rate,

" volatility factors, Risk Management Assets and Liabilities

" estimated correlation of energy commodity prices, and We record derivatives that qualify for designation as hedges

" expected generation profiles of specific regions. under SFAS No. 133 in "Risk management assets and liabilities" Additionally, we incorporate counterparty-specific credit in our Consolidated Balance Sheets. Our risk management assets quality and factors for market price and volatility uncertainty and liabilities consisted of the following:

and other risks in our valuation. The inputs and factors used to determine fair value reflect management's best estimates. At December 31, 2005 2004 The electricity, fuel, and other energy contracts we hold (In millions) have varying terms to maturity, ranging from contracts for Current Assets $1,244.3 $471.5 delivery the next hour to contracts with terms of ten years or Noncurrent Assets 626.0 306.2 more. Because an active, liquid electricity futures market Total Assets 1,870.3 777.7 comparable to that for other commodities has nor developed, the majority of contracts used in the wholesale marketing and risk Current Liabilities 483.5 304.3 management operation are direct contracts between market Noncurrent Liabilities 1,035.5 472.2 participants and are not exchange-traded or financially settling Total Liabilities 1,519.0 776.5 contracts that can be readily liquidated in their entirety through Net risk management asset $ 351.3 $ 1.2 an exchange or other market mechanism. Consequently, we and other market participants generally realize the value of these The significant increases in our gross risk management contracts as cash flows become due or payable under the terms assets and liabilities were due primarily to higher commodity of the contracts rather than through selling or liquidating the prices during 2005. These price increases resulted in larger contracts themselves. positions with individual counterparties which must be recorded Consistent with our risk management practices, the gross in our balance sheet unless a legal right of offset exists.

amounts shown in the table on the previous page as being The significant increase in our net risk management asset was valued using prices from external sources include the portion of due primarily to a contract that was previously designated as a long-term contracts for which we can obtain reliable prices from cash-flow hedge that we elected to de-designate and to which external sources. The remaining portions of these long-term the normal purchase and normal sales election was applied. At contracts are shown in the table as being valued using models. the point of de-designation, the fair value of the contract that In order to realize the entire value of a long-term contract in a was previously recorded in "Risk management liabilities" was single transaction, we would need to sell or assign the entire reclassified to "Unamortized energy contract liabilities." These contract. If we were to sell or assign any of our long-term increases in our net risk management asset were partially offset contracts in their entirety, we may not realize the entire value by the assumption of below-market power sale agreements in reflected in the table. However, based upon the nature of the connection with a customer contract restructuring. We discuss wholesale marketing and risk management operation, we expect the de-designation of the cash-flow hedge in more detail on the to realize the value of these contracts, as well as any contracts we next page. We discuss the customer contract restructuring may enter into in the future to manage our risk, over time as transaction in more detail in Note 4.

the contracts and related hedges settle in accordance with their terms. We do not expect to realize the value of these contracts and related hedges by selling or assigning the contracts themselves in total.

The fair values in the table represent expected future cash flows based on the level of forward prices and volatility factors as of December 31, 2005 and could change significantly as a result of future changes in these factors. Additionally, because the depth and liquidity of the power markets vary substantially between regions and time periods, the prices used to determine fair value could be affected significantly by the volume of transactions executed.

48

UnamortizedEnergy ContractAssets and Liabilities The increase in revenues in 2004 compared to 2003 is Unamortized energy contract assets and liabilities represent the primarily due to higher equity in earnings related to our remaining unamortized balance of nonderivative energy contracts minority investment in a facility that produces synthetic fuel that we acquired or derivatives designated as normal purchases from coal. This increase included $13.1 million of revenues and normal sales that we had previously recorded as related to an increased incentive fee and a deferred contingent "Mark-to-market energy assets and liabilities" or "Risk transaction fee.

management assets and liabilities." Our unamortized energy At December 31, 2005, our investment in qualifying contract assets and liabilities consisted of the following: facilities and domestic power projects consisted of the following:

At December 31, 2005 2004 Book Value at December 31, 2005 2004 (anmillions) (In millions)

Current Assets $ 55.6 $ 37.2 Project Type Noncurrent Assets 141.2 80.1 Coal $127.8 $128.7 Hydroelectric 55.9 55.8 Total Assets $ 196.8 $117.3 Geothermal 43.7 46.3 Current liabilities $ 489.5 $ 67.2 Biomass 48.0 50.2 Noncurrent Liabilities 1,118.7 86.2 Fuel Processing 23.8 22.5 Solar 7.0 10.4 Total Liabilities $1,608.2 $153.4 Total $306.2 $313.9 During 2005, we acquired several pre-existing nonderivative contracts that had been originated by other parties in prior We believe the current market conditions for our equity-periods when market prices were lower than current levels. Upon method investments that own geothermal, coal, hydroelectric, acquisition, we received approximately $530 million in cash and and fuel processing projects provide sufficient positive cash flows other consideration and recorded a liability in "Unamortized to recover our investments. We continuously monitor issues that energy contracts." In addition, during 2005, we designated as potentially could impact future profitability of these investments, normal purchases and normal sales contracts that we had including environmental and legislative initiatives. We discuss previously recorded as cash-flow hedges in "Risk management certain risks and uncertainties in more detail in our Forward liabilities." This change in designation resulted in a Looking Statements and Item IA. Risk Factorssections. However, reclassification of $888.5 million from "Risk management should future events cause these investments to become liabilities" to "Unamortized energy contracts." Since the original uneconomic, our investments in these projects could become forecasted transaction is still probable of occurring, the amount impaired under the provisions of APB No. 18.

recorded in "Accumulated other comprehensive income" upon The ability to recover our costs in our equity-method de-designation of the hedged position will remain and be investments that own biomass and solar projects is partially amortized along with the unamortized energy contract liability. dependent upon subsidies from the State of California. Under The de-designation and redassification had no impact on our the California Public Utility Act, subsidies currently exist in that earnings. the California Public Utilities Commission (CPUC) requires load-serving entities to identify a separate rate component to be Other collected from customers to fund the development of renewable 2005 2004 2003 resources technologies, including solar, biomass, and wind facilities. In addition, legislation in California requires that each (In millons) load-serving entity increase its total procurement of eligible Revenues $58.0 $73.6 $45.1 renewable energy resources by at least one percent per year so Our merchant energy business holds up to a 50% voting interest that 20% of its retail sales are procured from eligible renewable in 24 operating domestic energy projects that consist of electric energy resources by 2017. The CPUC accelerated the deadline generation, fuel processing, or fuel handling facilities. Of these for compliance to 2010. The legislation also requires the 24 projects, 17 are "qualifying facilities" that receive certain California Energy Commission to award supplemental energy exemptions based on the facilities' energy source or the use of a payments to load-serving entities to cover above-market costs of cogeneration process. Earnings from our investments were renewable energy.

$3.6 million in 2005, $18.0 million in 2004, and $2.1 million in 2003.

Other revenues decreased $15.6 million in 2005 compared to 2004 mostly due to an increased incentive fee and a deferred contingent transaction fee received from our synthetic fuel facilities located in Virginia and West Virginia that had a favorable impact in 2004.

49

Given the need for electric power and the desire for

• an increase in expenses due to the June 2004 acquisition renewable resource technologies, we believe California will of Ginna totaling $43.1 million, and continue to subsidize the use of renewable energy to make these " an increase of $10.1 million at our Nine Mile Point projects economical to operate. However, should the California nuclear facility primarily due to refueling outage and legislation fail to adequately support the renewable energy reliability spending.

initiatives, our equity-method investments in these types of projects could become impaired under the provisions of APB Merger-RelatedTransaction Costs No. 18, and any losses recognized could be material. If our We discuss our pending merger with FPL Group and related strategy were to change from an intent to hold to an intent to costs as discussed in more detail in Note 15.

sell for any of our equity-method investments in qualifying facilities or power projects, we would need to adjust their book Workforce Reduction Costs value to fair value, and that adjustment could be material. If we Our merchant energy business recognized expenses associated were to sell these investments in the current market, we may with our workforce reduction efforts as discussed in more detail have losses that could be material. in Note 2.

OperatingEpenes Depreciation,Depletion, and Amortization Eipense Our merchant energy business operating expenses increased Merchant energy depreciation, depletion, and amortization

$191.5 million in 2005 compared to 2004 mostly due to the expenses increased $30.4 million in 2005 compared to 2004 following: mostly due to:

" an increase of $101.8 million at our wholesale * $10.2 million related to our South Carolina synthetic marketing and risk management operation due to an fuel facility, increase in compensation and benefit costs including our * $8.8 million related to Ginna, which was acquired in expanding gas and coal operations, June 2004, and

" an increase of $81.5 million from Ginna, which was * $6.0 million increase related to our 2005 investments in acquired in June 2004, gas producing facilities.

" an increase of $26.5 million at our retail operation Merchant energy depreciation and amortization expense primarily related to a $10.8 million increase in increased $24.6 million in 2004 compared to 2003 mostly due uncollectible expenses and a $8.7 million increase in to:

aggregator fees, * $10.3 million related to Ginna,

" an increase of $13.9 million at our gas-fired generating * $6.9 million related to our High Desert facility, which facilities primarily due to increased corporate overhead commenced operations in 2003, and expenses, and * $5.1 million related to our South Carolina synthetic fuel

• an increase of $13.0 million at Calvert Cliffs primarily facility, which was acquired in May 2003.

due to an increase in corporate overhead expenses, partially offset by fewer employees and a shorter Accretion of Asset Retirement Obligations refueling outage in 2005. The increase in accretion expense of $8.9 million in 2005 These increases in expense were partially offset by lower compared to 2004 and $10.5 million in 2004 compared to operating expenses of $56.5 million at Nine Mile Point 2003 is primarily due to Ginna which was acquired in primarily due to lower refueling outage expenses and a lower June 2004 and the impact of normal compounding.

number of employees and contractors.

Our merchant energy business operating expenses increased Taxes Other Than Income Taxes

$240.0 million in 2004 compared to 2003 mostly due to the Merchant energy taxes other than income taxes increased following: $23.7 million in 2005 compared to 2004 mostly due to

• an increase of $94.3 million primarily related to higher $19.6 million related to higher gross receipts taxes at our retail compensation, benefit, and other inflationary costs, electric operation and $4.0 million related to property taxes for higher Sarbanes-Oxlcy 404 implementation costs of Ginna.

approximately $10 million, and higher spending on enterprise-wide information technology infrastructure costs of approximately $5 million,

• an increase at our competitive supply operations totaling

$90.1 million mostly because of higher compensation and benefit expense, including an increased number of employees to support the growth of these operations, 50

Regulated Electric Business These favorable results were partially offset by the Our regulated electric business is discussed in detail in Item 1. following:

Business-ElectricBusiness section.

• excluding the costs associated with Hurricane Isabel, we had increased operations and maintenance expenses of Results

$18.9 million after-tax mostly due to higher 2005 2004 2003 compensation and benefit costs, and the impact of (In millions) inflation on other costs, higher uncollectible expenses, Revenues $ 2,036.5 $ 1,967.7 $ 1,921.6 Sarbanes-Oxley 404 implementation costs, and increased Electricity purchased for resale expenses (1,068.9) (1,034.0) (1,023.5) spending on electric system reliability, and Operations and " increased depreciation and amortization expense of maintenance expenses (318.4) (304.2) (305.1) $7.6 million after-tax.

Merger-related transaction costs (4.0) - -

Workforce reduction costs - - (0.6) ElectricRevenues Depreciation and The changes in electric revenues in 2005 and 2004 compared to amortization (185.8) (194.2) (181.7) the respective prior year were caused by:

Taxes other than income taxes (135.3) (132.8) (130.2) 2005 2004 Income from Operations $ 324.1 $ 302.5 $ 280.5 (In millions)

Net Income $ 149.4 $ 131.1 $ 107.5 Distribution volumes $21.3 $15.8 Standard offer service 38.8 26.6 Other Items Included in Operations (after-tax)

Merger-related Total change in electric revenues from electric transaction costs $ (3.7) - - system sales 60.1 42.4 Workforce reduction Other 8.7 3.7 costs - - (0.4) Total change in electric revenues $68.8 $46.1 Total Other Items $ (3.7) $ - $ (0.4)

Above amounts include intercompany transactions eliminated in our Distribution Volumes ConsolidatedFinancialStatements. Note 3 provides a reconciliation Distribution volumes are the amount of electricity that BGE of operating results by segment to our ConsolidatedFinancial delivers to customers in its service territory. The percentage Statements. changes in our electric system distribution volumes, by type of Net income from the regulated electric business increased customer, in 2005 and 2004 compared to the respective prior

$18.3 million in 2005 compared to 2004 mostly because of the year were:

following:

2005 2004

" increased revenues less electricity purchased for resale expenses of $20.7 million after-tax, Residential 3.4% 4.4%

• decreased depreciation and amortization expense of Commercial 5.1 0.9

$5.1 million after-tax, and Industrial (6.4) (8.0)

" increased other income primarily due to gains on the In 2005, we distributed more electricity to residential sales of land of $3.6 million after-tax. customers compared to 2004 mostly due to warmer summer These favorable results were partially offset by the weather and an increased number of customers. We distributed following: more electricity to commercial customers mostly due to

• increased operations and maintenance expenses of increased usage per customer, an increased number of customers,

$8.7 million after-tax mostly due to higher and warmer summer weather. We distributed less electricity to compensation and benefit costs and the impact of industrial customers mostly due to decreased usage per customer.

inflation on other costs, and In 2004, we distributed more electricity to residential

" merger-related transaction costs of $3.7 million after-tax. customers compared to 2003 mostly due to increased usage per Net income from the regulated electric business increased customer, an increased number of customers, and warmer

$23.6 million in 2004 compared to 2003 mostly because of the summer weather. We distributed about the same amount of following: electricity to commercial customers. We distributed less

• increased revenues less electricity purchased for resale electricity to industrial customers mostly due to lower usage by expenses of $21.5 million after-tax, industrial customers.

• the absence of $19A million after-tax of incremental distribution service restoration expenses associated with Standard Offer Service Hurricane Isabel in 2003, and BGE provides standard offer service for customers that do not

" lower interest expense of $10.0 million after-tax. select an alternative supplier as discussed in Item 1. Business-Electric Regulatory Matters and Competition section.

51

Standard offer service revenues increased in 2005 compared Regulated electric operations and maintenance expenses to 2004 mostly because of increased standard offer service were about the same in 2004 compared to 2003. Hurricane volumes to residential customers and increased standard offer Isabel caused $32.1 million of incremental distribution service service rates for all customers partially offset by lower standard restoration expenses in 2003. Other operations and maintenance offer service volumes associated with those commercial and expenses increased $31.2 million in 2004 compared to 2003.

industrial customers that elected alternative suppliers beginning This increase was mostly due to:

July 1, 2004. " an increase in compensation and benefit cost, and the Standard offer service revenues increased in 2004 compared impact of inflation on other costs, to 2003 mostly because of increased standard offer service " a $9.0 million increase in uncollectible expenses, volumes to residential customers, partially offset by lower " approximately $4 million related to Sarbanes-Oxley 404 revenues associated with commercial and industrial customers implementation costs, and that elected an alternative supplier beginning July 1, 2004. " approximately $4 million in spending on electric systems reliability.

Electricity Purchasedfor Resale Eipenses BGE's actual costs of electricity purchased for resale expenses Merger-ReLated Transaction Costs increased $34.9 million in 2005 compared to 2004 mostly We discuss our pending merger with FPL Group and related because of increased standard offer service volumes to residential costs in more detail in Note 15.

customers and higher costs to serve all standard offer service customers, partially offset by lower electricity purchased for Workforce Reduction Costs resale expenses associated with commercial and industrial BGE's electric business recognized expenses associated with our customers that elected alternative suppliers beginning July 1, workforce reduction efforts as discussed in Note 2.

2004.

. BGE's actual costs of electricity purchased for resale ElectricDepreciationand Amortization Expense expenses increased $10.5 million in 2004 compared to 2003 Regulated electric depreciation and amortization expense mostly because of increased standard offer service volumes to decreased $8.4 million in 2005 compared to 2004 mostly residential customers and higher costs to serve all standard offer because of the absence of $12.6 million of accelerated service customers, partially offset by lower electricity purchased amortization expense associated with certain information for resale expenses associated with commercial and industrial technology assets replaced in 2004, partially offset by customers that elected an alternative supplier beginning July 1, $4.2 million related to additional property placed in service.

2004. Regulated electric depreciation and amortization expense increased $12.5 million in 2004 compared to 2003 mostly Electric Operationsand MaintenanceExpenses because of $7.6 million related to accelerated amortization Regulated electric operations and maintenance expenses increased expense associated with the replacement of information

$14.2 million in 2005 compared to 2004 mostly due to higher technology assets and $4.9 million related to additional property compensation and benefit costs and the impact of inflation on placed in service.

other costs.

52

Regulated Gas Business Gas Revenues Our regulated gas business is discussed in detail in Item I. The changes in gas revenues in 2005 and 2004 compared to the Business--Gas Business section. respective prior year were caused by:

Results 2005 2004 2005 2004 2003 (In millions)

(In millions)

Distribution volumes $ 3.9 $(7.2)

Revenues $ 972.8 $ 757.0 $ 726.0 Base rates 2.6 (0.1)

Gas purchased for resale Weather normalization 2.5 5.4 expenses (687.5) (484.3) (445.8) Gas cost adjustments 129.1 40.5 Operations and maintenance Total change in gas revenues from gas system expenses (131.8) (123.6) (101.1) sales 138.1 38.6 Merger-related transaction costs (1.4) - -

Off-system sales 77.5 (7.6)

Workforce reduction costs - - (0.1) Other 0.2 -

Depreciation and amortization (46.6) (48.1) (46.6)

Taxes other than income taxes (33.1) (32.1) (27.9) Total change in gas revenues $215.8 $31.0 Income from Operations $ 72.4 $ 68.9 $ 104.5 Net Income $ 26.7 $ 22.2 $ 43.0 Distribution Volumes The percentage changes in our distribution volumes, by type of Other Items Included in Operations (afier-tax) customer, in 2005 and 2004 compared to the respective prior Merger-related transaction year were:

costs $ (1.3) $ - $ -

Workforce reduction costs - - (0.1) 2005 2004 Total Other Items $ (1.3) $ - $ (0.1) (5.1)%

Residential (1.3)%

Above amounts include intercompany transactions eliminated in our Commercial (9.0) 10.1 ConsolidatedFinancialStatements. Note 3 provides a reconciliation Industrial 33.6 (22.3) of operating results by segment to our ConsolidatedFinancial In 2005, we distributed less gas to residential and Statements.

commercial customers compared to 2004 mostly due to Net income from our regulated gas business was about the same decreased usage per customer partially offset by colder winter in 2005 compared to 2004. weather and an increased number of customers. We distributed Net income from our regulated gas business decreased more gas to industrial customers mostly due to increased usage

$20.8 million in 2004 compared to 2003 mostly because of: per customer.

" increased operations and maintenance expenses of In 2004, we distributed less gas to residential customers

$13.6 million after-tax mostly due to increased compared to 2003 mostly due to milder winter weather and compensation, benefit, and other inflationary costs, lower usage per customer. We distributed more gas to higher uncollectible expenses, and Sarbanes-Oxley 404 commercial customers mostly due to increased usage and an implementation costs, increased number of customers. We distributed less gas to

• the absence of a $4.7 million after-tax recovery of a industrial customers mostly due to lower usage per customer.

previously disallowed regulatory asset following an order issued by the Maryland PSC that had a positive impact Base Rates in 2003, and In April 2005, BGE filed an application for a $52.7 million

• the absence of $2.2 million after-tax of property tax annual increase in its gas base rates. The Maryland PSC issued refund claims by the State of Maryland resulting from a an order in December 2005 granting BGE an annual increase of redassification of gas distribution pipeline from real $35.6 million. Certain parties to the proceeding have sought property to personal property that had a positive impact *judicial review and Maryland PSC rehearing of the decision.

in 2003. BGE will not seek review of any aspect of the order. We cannot provide assurance that a court will not reverse any aspect of the order or that it will not remand certain issues to the Maryland PSC.

53

Weather Normalization Revenues from off-system gas sales increased in 2005 The Maryland PSC allows us to record a monthly adjustment to compared to 2004 because we sold more gas at higher prices.

our gas distribution revenues to eliminate the effect of abnormal Revenues from off-system gas sales decreased in 2004 weather patterns on our gas distribution volumes. This means compared to 2003 mostly because of less gas sold.

our monthly gas distribution revenues are based on weather that is considered "normal" for the month and, therefore, are not Gas PurchasedFor Resale Eipenses affected by actual weather conditions. Gas purchased for resale expenses include the cost of gas purchased for resale to our customers and for off-system sales.

Gas Cost Adjustments These costs do not include the cost of gas purchased by delivery We charge our gas customers for the natural gas they purchase service only customers.

from us using gas cost adjustment clauses set by the Maryland Gas purchased for resale expenses increased in 2005 PSC as described in Note 1. However, under the market-based compared to 2004 because we purchased more gas at higher rates mechanism approved by the Maryland PSC, our actual cost prices.

of gas is compared to a market index (a measure of the market Gas purchased for resale expenses increased in 2004 as price of gas in a given period). The difference between our compared to 2003 mostly because of higher gas prices partially actual cost and the market index is shared equally between offset by less gas sold.

shareholders and customers.

Customers who do not purchase gas from BGE are not Gas Operationsand MaintenanceE-penses subject to the gas cost adjustment clauses because we are not Regulated gas operations and maintenance expenses increased selling gas to them. However, these customers are charged base $8.2 million in 2005 compared to 2004 mostly due to higher rates to recover the costs BGE incurs to deliver their gas through compensation and benefit costs and the impact of inflation on our distribution system, and are included in the gas distribution other costs.

volume revenues. Regulated gas operations and maintenance expenses Gas cost adjustment revenues increased in 2005 compared increased $22.5 million in 2004 compared to 2003 mostly to 2004 because we sold more gas at higher prices. because of:

Gas cost adjustment revenues increased in 2004 compared " an increase in compensation and benefit cost, and the to 2003 because we sold gas at a higher price partially offset by impact of inflation on other costs, less gas sold.

• a $5.4 million increase in uncollectible expenses, and

" approximately $1 million related to Sarbanes-Oxley 404 Off-System Sales implementation costs.

Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas outside our service territory. Merger-Related Transaction Costs Off-system gas sales, which occur after BGE satisfied its We discuss our pending merger with FPL Group and related customers' demand, are not subject to gas cost adjustments. The costs in more detail in Note 15.

Maryland PSC approved an arrangement for part of the margin from off-system sales to benefit customers (through reduced Workforce Reduction Costs costs) and the remainder to be retained by BGE (which benefits BGE's gas business recognized expenses associated with our shareholders). Changes in off-system sales do not significantly workforce reduction efforts as discussed in Note 2.

impact earnings.

54

Other Nonregulated Businesses Consolidated Nonoperating Income and Expenses Results Other Income 2005 2004 2003 Other income increased $37.5 million in 2005 compared to (In millions) 2004 primarily because of higher interest and investment income Revenues $ 207.0 $ 201.1 $ 399.6 due to a higher cash balance and higher decommissioning trust Operating expenses (156.2) (180.0) (355.1) asset earnings and gains on the sales of land at BGE.

Merger-related transaction costs (0.4) - - Other income increased $4.6 million during 2004 as Workforce reduction costs - - (0.2) compared to 2003 mostly because of higher earnings from Depreciation and amortization (40.2) (24.2) (11.0) consolidated investments where our ownership is less than Taxes other than income taxes (2.0) (2.4) (3.3) 100%, which resulted in increased minority interest expense.

Income from Operations $ 8.2 $ (5.5) $ 30.0 Total other income at BGE increased $12.3 million in Income from continuing operations and 2005 compared to 2004 primarily due to approximately before cumulative effects of changes $7 million of gains on the sales of land.

in accounting principles (after-tax) $ 0.4 $ (12.9) $ 5.1 Income from discontinued Fixed Charges operations (after-tax) 20.6 9.4 7.1 Total fixed charges decreased $16.7 million in 2005 compared to Cumulative effects of changes in 2004 mostly because of the benefit of lower interest rates due to accounting principles (after-tax) 0.2 - -

interest rate swaps entered into during the third quarter of 2004 Net Income (Loss) $ 21.2 $ (3.5) $ 12.2 and a lower level of debt outstanding. We discuss the interest Other Items Included In Operations (after-tax) rate swaps in more detail in Note 13.

Merger-related transaction costs $ (0.2) - - Total fixed charges decreased $9.7 million during 2004 as Workforce reduction costs - - (0.1) compared to 2003 mostly because of a lower level of debt Total Other Items $ (0.2) $ - $ (0.1) outstanding and the benefit of lower interest rates due to interest rate swaps entered into during the third quarter of 2004.

Certainprior-year amounts have been recdassified to conform with Total fixed charges for BGE decreased $2.7 million in 2005 the currentyear's presentation. compared to 2004 mostly because of a lower level of debt Above amounts include intercompany transactionseliminated in our outstanding.

ConsolidatedFinancialStatements. Note 3 provides a reconciliation Total fixed charges for BGE decreased $15.0 million during of operatingresults by segment to our ConsolidatedFinancial 2004 compared to 2003 mostly because of a lower level of debt Statements. outstanding.

Net income from our other nonregulated businesses increased Income Taxes

$24.7 million in 2005 compared to 2004 primarily due to:

The differences in income taxes result from a combination of

" a $16.1 million after-tax gain on sale of Constellation the changes in income and the impact of the recognition of tax Power International Investments, Ltd., which held our credits on the effective tax rate. We include an analysis of the other nonregulated international investments, in changes in the effective tax rate in Note 10.

October 2005, The Internal Revenue Code provides for a phase-out of

" a $13.2 million after-tax increase in net income from synthetic fuel tax credits if average annual wellhead oil prices the continued liquidation of our financial investments. increase above certain levels. Each year, we arc required to These increases were partially offset by $4.9 million lower compare average annual wellhead oil prices per barrel as net income from our other nonregulated international published by the Internal Revenue Service (IRS) (reference price) investments due to their sale in October 2005. We discuss the to a Gross National Product inflation adjusted oil price for the sale of our other nonregulated international investments in more year, also published by the IRS. The reference price is detail in Note 2. determined based on wellhead prices for all domestic oil Net income from our other nonregulated businesses production as published by the Energy Information decreased $15.7 million during 2004 compared to 2003 mostly Administration. For the twelve months ended December 31, because of a $16.4 million after-tax net gain on sales of 2005, we estimate that the reference price averaged investments and other assets in 2003 that had a positive impact approximately $6 per barrel lower than the NYMEX price for in that period. light, sweet crude oil. For 2006, we estimate the credit reduction In 2001, we decided to sell certain non-core assets and would begin if the reference price exceeds approximately $54 per accelerate the exit strategies on other assets that we continued to barrel and would be fully phased out if the reference price hold and own. While our intent is to dispose of these remaining exceeds approximately $68 per barrel.

non-core assets, market conditions and other events beyond our If oil prices remain at high levels, a portion of our synthetic control may affect the actual sale of these assets. In addition, a fuel tax credits could be phased-out in 2006 and 2007. Market future decline in the fair value of these assets could result in forwards and volatilities as of mid-February 2006 would indicate losses that could have a material impact on our financial results.

55

a 25-35% tax credit phase-out (approximately $35-$50 million) with SFAS No. 87, Enmployers' Accountingfor Pensions. Differences in 2006. between actual and expected returns are deferred along with We actively monitor and manage our exposure to synthetic other actuarial gains and losses and reflected in future net fuel tax credit phase-out as part of our ongoing hedging periodic pension expense in accordance with SFAS No. 87.

activities. In addition, we may reduce synthetic fuel production Expected and actual returns on pension assets also are affected depending on our expectation of the level of tax credit by plan contributions. Effective in 2006, we have reduced our phase-out. The objective of these activities is to reduce the assumed expected return on pension plan assets from 9.0% to potential losses we could incur if the reference price in a year 8.75% based on a fundamental analysis utilizing expected long-exceeds a level triggering a phase-out of synthetic fuel tax credits. term returns applied to our targeted asset allocation.

While we believe the production and sale of synthetic fuel Effective December 31, 2005, we also changed the from all of our synthetic fuel facilities meet the conditions to mortality table we are utilizing to determine our benefit qualify for tax credits under the IRC, we cannot predict the obligation and annual expense to reflect more current life timing or outcome of any future challenge by the IRS, legislative expectancy experience.

or regulatory action, oil prices, the effectiveness of our hedging The combined impact of these changes will increase 2006 program, or the ultimate impact of such events on the synthetic and subsequent year pension and postretirement benefit expense fuel tax credits that we have claimed to date or expect to claim by approximately $14 million.

in the future, but the impact could be material to our financial We expect to contribute $52 million to our pension plans results. in 2006, even though there is no required IRS minimum contribution for 2006.

Pension Expense At December 31, 2005, we recorded an after-tax charge to Our actual return on our qualified pension plan assets was 7.4% equity of $77.1 million as a result of increasing our additional for the year ended December 31, 2005. In 2005, we assumed an minimum pension liability. We discuss our pension plans in expected return on pension plan assets of 9.0% for the purpose more detail in Note 7.

of computing annual net periodic pension expense in accordance 56

Financial Condition Cash Flows The following table summarizes our 2005 cash flows by business segment, as well as our consolidated cash flows for 2005, 2004, and 2003.

2005 Segment Cash Flows Consolidated Cash Flows Merchant Regulated Other 2005 2004 2003 (In millions)

Operating Activities Net income $ 425.8 $176.1 $ 21.2 $ 623.1 $ 539.7 $ 277.3 Non-cash adjustments to net income 475.8 220.9 55.0 751.7 916.4 944.2 Changes in working capital (686.7) (64.0) (24.6) (775.3) (319.6) (50.0)

Pension and postemployment benefits' 23.6 (3.0) (69.4)

Other (13.8) (33.8) 51.7 4.1 (46.7) (44.3)

Net cash provided by operating activities 201.1 299.2 103.3 627.2 1,086.8 1,057.8 Investing activities Investments in property, plant and equipment (464.7) (269.3) (26.0) (760.0) (703.6) (635.7)

Contract and portfolio acquisitions (336.2) - - (336.2) - -

Asset acquisitions and business combinations, net of cash acquired (216.3) - (20.9) (237.2) (457.3) (546.6)

Investment in nuclear decommissioning trust fund securities (370.8) - - (370.8) (424.2) (176.0)

Proceeds from nuclear decommissioning trust funds securities 353.2 - - 353.2 402.2 162.8 Net proceeds from sale of discontinued operations 217.6 - 71.8 289.4 72.7 -

Sale of investments and other assets 0.4 11.0 3.0 14.4 36.1 148.8 Issuances of loans receivable (82.8) - - (82.8) - -

Other investments (36.8) (10.4) 3.2 (44.0) (78.6) (113.6)

Net cash (used in) provided by investing activities (936.4) (268.7) 31.1 (1,174.0) (1,152.7) (1,160.3)

Cash flows from operating activities less cash flows from investing activities $ (735.3) $ 30.5 $134.4 (546.8) (65.9) (102.5)

Financing Activities Net (repayment) issuance of debt* (339.6) (152.8) 274.9 Proceeds from issuance of common stock! 96.9 293.9 95.4 Common stock dividends paid* (228.8) (189.7) (169.2)

Proceeds from contract and portfolio acquisitions 1,026.9 117.5 -

Other* 98.1 (18.0) 7.7 Net cash provided by financing activities 653.5 50.9 208.8 Net increase (decrease) in cash and cash equivalents $ 106.7 $ (15.0) $ 106.3

• Items are not allocated to the business segments because they are managedfor the company as a whole.

Cash Flowsfrom OperatingActivities business growth. This was partially offset by an increase of Cash provided by operating activities was $627.2 million in $142 million of net cash collateral received, which was also due 2005 compared to $1,086.8 million in 2004. Net income was to higher commodity prices.

higher by $83.4 million in 2005 compared to 2004. Non-cash Cash provided by operating activities was $1,086.8 million adjustments to net income were $164.7 million lower in 2005 in 2004 compared to $1,057.8 million in 2003. Non-cash compared to 2004. The decrease in non-cash adjustments to net adjustments to net income were $27.8 million lower in 2004 income was primarily due to the reclassification of $72.6 million compared to 2003. The decrease in non-cash adjustments to net of proceeds from derivative power sales contracts as financing income was primarily due to the cumulative effects of changes in activities under SFAS No. 149, Amendment ofFASB Statement accounting principles of $198.4 million as a result of the No. 133 on Derivative and HedgingActivities and $63.9 million adoption of SFAS No. 143 and EITF 02-3 in 2003, which had related to the impact of discontinued operations. the effect of reducing net income in 2003 but were non-cash Changes in working capital had a negative impact of transactions. This decrease in non-cash adjustments to net

$775.3 million on cash flow from operations in 2005 compared income was offset in part by the following increases in non-cash to a negative impact of $319.6 million in 2004. The decrease of adjustments in 2004:

$455.7 million was due to a $598 million unfavorable change in

• higher depreciation and amortization and accretion of working capital primarily related to our accounts receivable, asset retirement obligations of $61 million, accounts payable, and fuel stocks mostly due to higher " the loss on sale of discontinued operations of commodity prices, increased value of emissions credits, and $50 million, 57

" a decrease in the net gain on sales of investments and Cash Flowsfrom FinancingActivities other assets of $27 million primarily due to the sale of Cash provided by financing activities was $653.5 million in financial and real estate investments in 2003. We adjust 2005 compared to $50.9 million in 2004. The increase in 2005 net income to exclude these gains and reflect the compared to 2004 was mostly due to an increase in proceeds proceeds from these sales in the investing activities from contract and portfolio acquisitions of $909.4 million. We sections, and discuss proceeds from contract and portfolio acquisitions in

• an increase in deferred income taxes of $14 million. more detail below. This increase in cash provided by financing Changes in working capital had a negative impact of activities was partially offset by a reduction in proceeds from

$319.6 million on cash flow from operations in 2004 compared issuances of common stock, an increase in cash used for to a negative impact of $50.0 million in 2003. The repayments of debt, and higher dividend payments in 2005

$269.6 million decrease in cash due to working capital changes compared to 2004.

was primarily due to the following uses of cash in 2004 Cash provided by financing activities decreased compared to 2003: $157.9 million in 2004 compared to 2003 mostly due to lower

" a decline in working capital related to accrued taxes of issuance of net debt in 2004 compared to 2003, partially offset approximately $254 million in 2004 compared to 2003 by higher proceeds from common stock issuances.

due to higher income tax payments in 2004 compared to refunds of taxes in 2003 and due to the timing of Contract and Portfolio Acquisitions income tax accruals in 2004 compared to 2003, During 2004 and 2005, our merchant energy business acquired

• a $48 million unfavorable change in working capital several pre-existing energy purchase and sale agreements, which relating to our accounts receivable and accounts payable generated significant cash flows at the inception of the contracts.

primarily due to increased volumes associated with our These agreements had contract prices that differed from market merchant energy business and the termination of an prices at dosing, which resulted in cash payments from the accounts receivable securitization program in 2004, and counterparty at the acquisition of the contract. We received

• an unfavorable change of approximately $61 million $117.5 million in 2004 and $690.7 million in 2005 for various relating to fuel stocks during 2004 primarily due to contract and portfolio acquisitions. We reflect the underlying higher gas and coal prices, which affected inventory contracts on a gross basis as assets or liabilities in our levels at BGE and our merchant energy business. Consolidated Balance Sheets depending on whether they were at These items were partially offset by a source of cash of above- or below-market prices at closing; therefore, we have also approximately $90 million in 2004 compared to 2003 primarily reflected them on a gross basis in cash flows from investing and due to other favorable working capital changes as a result of financing activities in our Consolidated Statements of Cash higher accrued expenses in 2004 compared to 2003. Flows as follows:

Year ended December 31, 2005 2004 Cash Flowsfrom InvestingActivities Cash used in investing activities was $1,174.0 million in 2005 (In millions) compared to $1,152.7 million in 2004. The slight increase in Financing activities-proceeds from cash used in investing activities was mostly due to contract and portfolio acquisitions $1,026.9 $117.5

$336.2 million of cash paid for contract and portfolio Investing activities-contract and portfolio acquisitions and $82.8 million in issuances of loans receivable acquisitions (336.2) -

related primarily to a customer contract restructuring. We Cash flows from contract and portfolio discuss contract and portfolio acquisitions in more detail below, acquisitions $ 690.7 $117.5 and the customer contract restructuring is discussed in more We record the proceeds we receive to acquire energy detail in Note 4. These increases in cash used in 2005 compared to 2004 were partially offset by less cash paid for asset purchase and sale agreements as a financing cash inflow because acquisitions and business combinations of $220.1 million in it constitutes a prepayment for a portion of the market price of 2005 compared to 2004 and an increase in cash proceeds from energy, which we will buy or sell over the term of the the sale of discontinued operations of $216.7 million, primarily agreements and does not represent a cash inflow from current due to the sale of Oleander and our other nonregulated period operating activities. For those acquired contracts that are derivatives, we record the ongoing cash flows related to the international investments in 2005 as discussed in more detail in contract with the counterparties as financing cash inflows in Note 2.

accordance with SFAS No. 149.

Cash used in investing activities in 2004 was about the We discuss certain of these contract and portfolio same as in 2003 primarily due to the decrease in cash used for acquisitions and proceeds from the sale of discontinued acquisitions in more detail in Note 4 and Note 5.

operations in 2004, substantially offsetting increased spending on property, plant and equipment and a decrease in cash proceeds from the sale of investments and other assets in 2004 compared to 2003.

58

Security Ratings " a $1.1 billion five-year revolving credit facility that Independent credit-rating agencies rate Constellation Energy's expires in November 2010, and and BGE's fixed-income securities. The ratings indicate the

• a $750 million five-year revolving credit facility that agencies' assessment of each company's ability to pay interest, expires in November 2010.

distributions, dividends, and principal on these securities. These We enter into these facilities to ensure adequate liquidity to ratings affect how much it will cost each company to sell these support our operations. Currently, we use the facilities to issue securities. The better the rating, the lower the cost of the letters of credit primarily for our merchant energy business.

securities to each company when they sell them. Additionally, we can borrow directly from the banks or use the The factors that credit rating agencies consider in facilities to allow the issuance of commercial paper with the establishing Constellation Energy's and BGE's credit ratings exception of the $200 million bilateral facility, which only include, but are not limited to, cash flows, liquidity, business supports letters of credit. We had $290.0 million of commercial risk profile, and the amount of debt as a component of total paper outstanding at February 28, 2006.

capitalization. At the date of this report, our credit ratings were These revolving credit facilities allow the issuance of letters as follows: of credit up to approximately $3.6 billion. At December 31, Standard 2005, letters of credit that totaled $2.5 billion were issued under

& Poors Moody's all of our facilities, which results in approximately $1.1 billion of Rating Investors Fitch-Group Service Ratings unused credit facilities.

We expect to fund future acquisitions with an overall goal Constellation Energy of maintaining a strong investment grade credit profile.

Commercial Paper A-2 P-2 F-2 Senior Unsecured Debt BBB Baal A-BGE BGE Commercial Paper A-2 P-1 F-I BGE maintains $200.0 million in annual committed credit Mortgage Bonds A Al A+ facilities, expiring May 2006 through November 2006. BGE can Senior Unsecured Debt BBB+ A2 A borrow directly from the banks or use the facilities to allow Trust Preferred Securities BBB- A3 A- commercial paper to be issued. As of December 31, 2005, BGE Preference Stock BBB- Baal A- had no outstanding commercial paper, which results in In December 2005, in conjunction with the announcement $200.0 million in unused credit facilities.

of the pending merger between Constellation Energy and FPL Group, Standard & Poors Rating Group and Moody's Investors Other NonregulatedBusinesses Service reviewed our ratings and took the following actions: If we can get a reasonable value for our remaining real estate

" Moody's Investor Service revised Constellation Energy's projects and other investments, additional cash may be obtained rating outlook to positive from stable and maintained by selling them. Our ability to sell or liquidate assets will BGE's stable rating outlook, and depend on market conditions, and we cannot give assurances

" Standard & Poor's Ratings Services placed the ratings on that these sales or liquidations could be made.

Constellation Energy and our subsidiaries on creditwatch with positive implications. Capital Resources Fitch-Ratings outlook for Constellation Energy and BGE Our actual consolidated capital requirements for the years 2003 remains stable. We discuss the pending merger in more detail in through 2005, along with the estimated annual amount for Note 15. 2006, are shown in the table on the next page.

We will continue to have cash requirements for:

Available Sources of Funding

• working capital needs, We continuously monitor our liquidity requirements and believe

• payments of interest, distributions, and dividends, that our credit facilities and access to the capital markets provide

• capital expenditures, and sufficient liquidity to meet our business requirements. We

• the retirement of debt and redemption of preference discuss our available sources of funding in more detail below. stock.

Capital requirements for 2006 and 2007 include estimates Constellation Energy of spending for existing and anticipated projects. We In addition to our cash balance, we have a commercial paper continuously review and modify those estimates. Actual program under which we can issue short-term notes to fund our requirements may vary from the estimates included in the table subsidiaries. At December 31, 2005, we had approximately on the next page because of a number of factors including:

$3.6 billion of credit under several facilities. These facilities

• regulation, legislation, and competition, include:

• BGE load requirements,

" a $200 million 364-day bilateral line of credit that " environmental protection standards, expires in December 2006, " the type and number of projects selected for

" a $1.5 billion five-year revolving credit facility that construction or acquisition, expires in March 2010, 59

" the effect of market conditions on those projects, " costs of complying with the Environmental Protection

" the cost and availability of capital, Agency (EPA), Maryland, and Pennsylvania nitrogen

• the availability of cash from operations, and oxides (NO2) and sulfur dioxide (SO2) emissions

• business decisions to invest in capital projects. regulations, and Our estimates are also subject to additional factors. Please " enhancements to our information technology see the ForwardLooking Statements section. infrastructure.

2003 2004 2005 2006 Regulated Electric and Gas (In millions)

Regulated electric and gas construction expenditures primarily Nonregulated Capital Requirements: include new business construction needs and improvements to Merchant energy (excludes existing facilities, including projects to improve reliability.

acquisitions) Capital requirements for 2003 in the table above include Generation plants $175 $182 $ 182 $ 195 $32.0 million in costs incurred as a result of Hurricane Isabel to Nuclear fuel 59 133 130 140 restore the electric distribution system.

Environmental controls 12 - 1 40 Portfolio acquisitions/ Funding for Capital Requirements investments 51 11 231 395 Merchant Energy Business Technology/other 122 129 165 185 Funding for the expansion of our merchant energy business is Total merchant energy capital expected from internally generated funds. We also have available requirements 419 455 709 955 sources from commercial paper issuances, issuances of long-term Other nonregulated capital debt and equity, leases, and other financing activities.

requirements 53 42 32 20 The projects that our merchant energy business develops Total nonregulated capital typically require substantial capital investment. Many of the requirements 472 497 741 975 qualifying facilities and independent power projects that we have Regulated Capital Requirements: an interest in are financed primarily with non-recourse debt that Regulated electric 236 209 241 275 is repaid from the project's cash flows. This debt is collateralized Regulated gas 53 56 50 95 by interests in the physical assets, major project contracts and Total regulated capital agreements, cash accounts and, in some cases, the ownership requirements 289 265 291 370 interest in that project.

Total capital requirements $761 $762 $1,032 $1,345 We expect to fund acquisitions with a mixture of debt and The table above does not include amounts related to pre-acquisition equity with an overall goal of maintaining a strong investment capital requirements but does include post-acquisition capital grade credit profile.

requirements. We discuss our acquisitions in more detail in Note 15.

Regulated Electric and Gas As of the date of this report, we have not completed our Funding for regulated electric and gas capital expenditures is 2007 capital budgeting process, but expect our 2007 capital expected from internally generated funds. During 2006, we requirements to be approximately $1,330 million. expect our regulated business to generate sufficient cash flows Our environmental controls capital requirements are from operations to meet BGE's operating requirements. If affected by new rules or regulations that require modifications to necessary, additional funding may be obtained from commercial our facilities. Based on information currently available to us paper issuances, available capacity under credit facilities, the regarding recently issued regulations, we will install additional air issuance of long-term debt, trust preferred securities, or emission control equipment at our coal-fired generating facilities preference stock, and/or from time to time equity contributions in Maryland and at co-owned coal-fired generating facilities in from Constellation Energy. BGE also participates in a cash pool Pennsylvania. We estimate another $400-$500 million of capital administered by Constellation Energy as discussed in Note 16.

spending from 2008-2010. We discuss environmental matters in more detail in Item 1. Business--EnvironmentalMatters. Other NonregulatedBusinesses Funding for our other nonregulated businesses is expected from Capital Requirements internally generated funds, commercial paper issuances, issuances MerchantEnergy Business of long-term debt of Constellation Energy, sales of securities and Our merchant energy business' capital requirements consist of its assets, and/or from time to time equity contributions from continuing requirements, including expenditures for: Constellation Energy.

" improvements to generating plants, Our ability to sell or liquidate securities and non-core assets

• nuclear fuel costs, will depend on market conditions, and we cannot give

" upstream gas investments, assurances that these sales or liquidations could be made. We

" portfolio acquisitions and other investments, discuss our remaining non-core assets and market conditions in the Results of Operations-OtherNonregulatedBusinesses section.

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Contractual Payment Obligations and The table below presents our contingent obligations. Our Committed Amounts contingent obligations increased $4.4 billion during 2005, We enter into various agreements that result in contractual primarily due to the issuance of additional letters of credit and payment obligations in connection with our business activities. guarantees by the parent company for subsidiary obligations to These obligations primarily relate to our financing arrangements third parties in support of the growth of our merchant energy (such as long-term debt, preference stock, and operating leases), business. These amounts do not represent incremental purchases of capacity and energy to support the growth in our consolidated Constellation Energy obligations; rather, they merchant energy business activities, and purchases of fuel and primarily represent parental guarantees of certain subsidiary transportation to satisfy the fuel requirements of our power obligations to third parties. Our calculation of the fair value of generating facilities. subsidiary obligations covered by the $8,268.5 million of parent Our total contractual payment obligations as of company guarantees was $2,830.5 million at December 31, December 31, 2005, increased $2.1 billion compared to 2004 2005. Accordingly, if the parent company was required to fund primarily due to an increase in fuel and transportation subsidiary obligations, the total amount based on December 31, obligations. The increase in fuel and transportation obligations 2005 market prices is $2,830.5 million.

was mostly due to increased gas prices due to supply and demand imbalances and hurricane-related disruptions in the Gulf Expiration Coast and new contracts related to gas and nuclear fuel 2007- 2009-2006 2008 2010 Thereafter Total procurement. We detail our contractual payment obligations as of December 31, 2005 in the following table: (anmillions)

Contingent Oblsgations Payments Letters of credit $2,477.5 $ 8.6 $ - $ - $ 2,486.1 2007- 2009- Guarantees-competitive 2006 2008 2010 Thereafter Total supply' 5,514.1 546.1 251.6 1,956.7 8,268.5 (In millions)

Other guarantees, net 2 5.6 13.3 1.8 1,237.0 1,257.7 ContractualPayment Obligations Long-term debt:' Total contingent obligations $7,997.2 $568.0 $253.4 $3,193.7 $12,012.3 Nonregulated Principal S 21.7 S 627.4 $ 501.4 $2,256.1 $ 3,406.6 1 While the face amount of these guaranteesis $8,268.5 million, ut would not Interesr 213.7 358.8 309.4 1,647.6 2,529.5 expect to fund thefull amosest. In the eveat the parent were requiredto fuYll Total 235.4 986.2 810.8 3,903.7 5,936.1 subsidiary obligations, our calkulation of the fair 'alue of obligations covered by BGE these guarantees was $2,830.5 millon at December 31, 2005.

Principal 444.6 416.8 11.5 589.1 1,462.0 2 Other guaranteesin the above table are shown net of liabilities of $25.0 million Interest 83.9 97.5 71.2 775.1 1,027.7 recorded at December 31, 2005 in our Consolidated BalanceSheets.

Total 528.5 514.3 82.7 1,364.2 2,489.7 BGE preference stock - - - 190.0 190.0 PendingMerger with FPL Group, Inc.

2 Operating leases 159.6 262.6 93.8 325.5 841.5 Purchase obligations:' In connection with the merger agreement with FPL Group, Purchased capacity and there are certain contingencies relating to termination fees. We 4

energy 697.6 891.5 308.5 162.7 2,060.3 Fuel and transportation 2,360.3 1,054.6 436.2 575.5 4,426.6 discuss these contingencies in Note 15. In addition, as a result of Ocher 140.3 137.7 46.5 145.6 470.1 the change in control provisions in our long-term incentive Other noncurrent liabilities: plans, we will be required to pay cash of approximately Postretirement and postemployment $130 million (based on estimated fair value of outstanding benefitsl 33.2 76.7 83.9 188.8 382.6 awards at December 31, 2005) to settle certain stock-based Total contractual payment compensation awards if we complete our pending merger with obligations $4,154.9 $3,923.6 $1,862.4 $6,856.0 $16,796.9 FPL Group. We discuss our long-term incentive plans in more 1 Amounts in long-term debt refletr the originalmaturity date. Investors may require detail in Note 14.

us to repay $282.3 millZon early through put options and remarketingfeatures.

Interest on variable rate debt is included based on the December 31, 2005forward curve for interest rates. Liquidity Provisions 2 Our operating lease commitments includefuturepa*ment obligations under certain In many cases, customers of our merchant energy business rely power purchase agreements as discursedfurther in Note 11.

3 Contracai to purchase goods or services that specs)5 all significant terms. Amounts on the creditworthiness of Constellation Energy. A decline below relatedto certainpurchase obligations are based onfusurepurchase expectations investment grade by Constellation Energy would negatively which may differ from actual purchass. impact the business prospects of that operation.

4 Our contractualobligationsfor purchasedcapacity and energy are shown on a gross basis fir certain transactions, including both the fixed payment portions of tolling We regularly review our liquidity needs to ensure that we contracts and estimated variablepayments under unit-contingentpower purchase have adequate facilities available to meet collateral requirements.

agreements. We have recorded $3.0 million of liabilties related to purchased capacit and energy obligations at December 31, 2005 in our Consolidated This includes having liquidity available to meet margin Balance Sheem requirements for our wholesale marketing and risk management 5 Amounts relatedto postretirementandpostempklyment benefits arefor unfunded plans and reflect present value amounts consistent with the determination of the operation and our retail competitive supply activities.

related liabilitiesrecorded in our ConsolidatedBalance Sheets as discussed in We have certain agreements that contain provisions that Note Z would require additional collateral upon credit rating decreases in the senior unsecured debt of Constellation Energy. Decreases in Constellation Energy's credit ratings would not trigger an early payment on any of our credit facilities.

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Under counterparry contracts related to our wholesale threshold. Certain BGE credit facilities also contain usual and marketing and risk management operation, we are obligated to customary cross-default provisions that apply to defaults on debt post collateral if Constellation Energy's senior unsecured credit by BGE over a specified threshold. The indentures pursuant to ratings declined below established contractual levels. Based on which BGE has issued and outstanding mortgage bonds and contractual provisions at December 31, 2005, we estimate that if subordinated debentures provide that a default under any debt Constellation Energy's senior unsecured debt were downgraded instrument issued under the relevant indenture may cause a we would have the following additional collateral obligations: default of all debt outstanding under such indenture.

Constellation Energy also provides credit support to Calvert Credit Ratings Incremental Cumulative Cliffs, Nine Mile Point, and Ginna to ensure these plants have Downgraded to Obligations Obligations funds to meet expenses and obligations to safely operate and (In millions) maintain the plants.

BBB-/Baa3 $ 361 $ 361 As discussed in the Regulation by the Maryland PSC section, Below investment grade 1,286 1,647 the Maryland PSC and the Maryland General Assembly are Based on market conditions and contractual obligations at considering proposals to defer recovery of costs to be incurred by the time of a downgrade, we could be required to post collateral BGE to provide residential POLR service beginning July 2006.

in an amount that could exceed the amounts specified above, Any decision to defer or limit recovery of such costs could have which could be material. We assess the risk of being downgraded a material impact on our, or BGE's, liquidity.

to below investment grade as remote. However, we actively We discuss our short-term credit facilities in Note 8, monitor our collateral obligations and liquidity. We discuss our long-term debt in Note 9, lease requirements in Note 11, and credit facilities in the Available Sources of Fundingsection. commitments and guarantees in Note 12.

The credit facilities of Constellation Energy and BGE have limited material adverse change clauses that only consider a Off-Balance Sheet Arrangements material change in financial condition and are not directly For financing and other business purposes, we utilize certain affected by decreases in credit ratings. If these clauses are off-balance sheet arrangements that are not reflected in our invoked, the lending institutions can decline to make new Consolidated Balance Sheets. Such arrangements do not advances or issue new letters of credit, but cannot accelerate the represent a significant part of our activities or a significant payment of existing amounts outstanding. The long-term debt ongoing source of financing.

indentures of Constellation Energy and BGE do not contain We use these arrangements when they enable us to obtain material adverse change clauses or financial covenants. financing or execute commercial transactions on favorable terms.

Certain credit facilities of Constellation Energy contain a As of December 31, 2005, we have no material off-balance sheet provision requiring Constellation Energy to maintain a ratio of arrangements including:

debt to capitalization equal to or less than 65%. At " guarantees with third-parties that are subject to the December 31, 2005, the debt to capitalization ratios as defined initial recognition and measurement requirements of in the credit agreements were no greater than 59%. Certain FASB Interpretation No. 45, GuarantorsAccounting and credit agreements of BGE contain provisions requiring BGE to Disclosure Requirementsfor Guarantees,Including Indirect maintain a ratio of debt to capitalization equal to or less than Guarantees ofIndebtedness to Others, 65%. At December 31, 2005, the debt to capitalization ratio for

• retained interests in assets transferred to unconsolidated BGE as defined in these credit agreements was 45%. At entities, December 31, 2005, no amount was outstanding under these

• derivative instruments indexed to our common stock, agreements. and classified as equity, or Failure by Constellation Energy, or BGE, to comply with

• variable interests in unconsolidated entities that provide these provisions could result in the acceleration of the maturity financing, liquidity, market risk or credit risk support, of the debt outstanding under these facilities. The credit facilities or engage in leasing, hedging or research and of Constellation Energy contain usual and customary cross- development services.

default provisions that apply to defaults on debt by We discuss our guarantees in Note 12 and our significant Constellation Energy and certain subsidiaries over a specified variable interests in Note 4.

Market Risk program is predicated on a strong risk management culture We are exposed to various risks, including, but not limited to, combined with an effective system of internal controls.

energy commodity price and volatility risk, credit risk, interest The Audit Committee of the Board of Directors rate risk, equity price risk, foreign exchange risk, and operations periodically reviews compliance with our risk parameters, limits risk. Our risk management program is based on established and trading guidelines and our Board of Directors has policies and procedures to manage these key business risks with established a value at risk limit. We have a Risk Management a strong focus on the physical nature of our business. This Division that is responsible for monitoring the key business risks, enforcing compliance with risk management policies and 62

risk limits, as well as managing credit risk. The Risk major operating subsidiaries that meet regularly to identify, Management Division reports to the Chief Risk Officer (CRO) assess, and quantify material risk issues and to develop strategies who provides regular risk management updates to the Audit to manage these risks.

Committee and the Board of Directors.

We have a Risk Management Committee (RMC) that is Interest Rate Risk responsible for establishing risk management policies, reviewing We are exposed to changes in interest rates as a result of procedures for the identification, assessment, measurement and financing through our issuance of variable-rate and fixed-rate management of risks, and the monitoring and reporting of risk debt and certain related interest rate swaps. We may use exposures. The RMC meets on a regular basis and is chaired by derivative instruments to manage our interest rate risks.

the Vice Chairman of Constellation Energy & Chairman of In July 2004, to optimize the mix of fixed and floating-rate Constellation Energy Commodities Group, and consists of our debt, we entered into interest rare swaps relating to $450 million Chief Executive Officer, our Chief Financial Officer and Chief of our long-term debt. These fair value hedges effectively convert Administrative Officer, our Executive Vice President of our current fixed-rate debt to a floating-rate instrument tied to Corporate Strategy and Retail Competitive Supply, the the three month London Inter-Bank Offered Rate. Including the Co-Presidents & Chief Executive Officers of Constellation $450 million in interest rate swaps, approximately 14% of our Energy Commodities Group, the President of Constellation long-term debt is floating-rate.

Generation Group and the Chief Risk Officer. In addition, the The following table provides information about our debt CRO coordinates with the risk management committees at the obligations that are sensitive to interest rate changes:

PrincipalPayments and Interest Rate Detailby ContractualMaturity Date Fair value at December 31, 2006 2007 2008 2009 2010 Thereafier Total 2005 (Dollars in millions)

Long-term debt Variable-rate debt $ 97.4 $ - $ - $-- $ - $ 601.9 $ 699.3 $ 699.3 Average interest rate 4.41% -- % -- % --% -- % 5.76% 5.57%

Fixed-rate debt $368.9(A) $743.3 $300.9 $512.9 $ - $2,243.3 $4,169.3 $4,379.3 Average interest rate 5.41% 6.47% 6.30% 6.13% -- % 6.38% 6.37%

(A) Amount excludes $282.3 million of long-term debt that contains certainput options under which lenders could potentially require us to repay the debt prior to maturity of which $25.0 million is clasified as currentportion oflong-term debt in our ConsolidatedBalance Sheets and in our ConsolidatedStatements of Capitalization.

Commodity Risk A number of factors associated with the structure and We are exposed to the impact of market fluctuations in the price operation of the energy markets significantly influence the level and transportation costs of electricity, natural gas, coal, and and volatility of prices for energy commodities and related other commodities. These risks arise from our ownership and derivative products. We use such commodities and contracts in operation of power plants, the load-serving activities of BGE and our merchant energy business, and if we do not properly hedge our competitive supply operations, and our origination and risk the associated financial exposure, this commodity price volatility management activities. We discuss these risks separately for our could affect our earnings. These factors include:

merchant energy and our regulated businesses below.

• seasonal, daily, and hourly changes in demand,

" extreme peak demands due to weather conditions, Merchant Energy Business " available supply resources, Our merchant energy business is exposed to various risks in the " transportation availability and reliability within and competitive marketplace that may materially impact its financial between regions, results and affect our earnings. These risks include changes in " location of our generating facilities relative to the commodity prices, imbalances in supply and demand, and location of our load-serving obligations, operations risk.

• procedures used to maintain the integrity of the physical electricity system during extreme conditions, Commodity Prices

• changes in the nature and extent of federal and state Commodity price risk arises from: regulations, and

" the potential for changes in the price of, and

• geopolitical concerns affecting global supply of oil and transportation costs for, electricity, natural gas, coal, and natural gas.

other commodities, -

These factors can affect energy commodity and derivative

" the volatility of commodity prices, and prices in different ways and to different degrees. These effects

" changes in interest rates and foreign exchange rates.

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may vary throughout the country as a result of regional unplanned outage were to occur at Calvert Cliffs during periods differences in: when demand was high, we may have to purchase replacement

" weather conditions, power at potentially higher prices to meet our obligations, which

• market liquidity, could have a material adverse impact on our financial results.

" capability and reliability of the physical electricity and gas systems, and Risk Management

" the nature and extent of electricity deregulation. As part of our overall portfolio, we manage the commodity price Additionally, we have fuel requirements that are subject to risk of our competitive supply activities and our electric future changes in coal, natural gas, and oil prices. Our power generation facilities, including power sales, fuel and energy generation facilities purchase fuel under contracts or in the spot purchases, emission credits, interest rate and foreign currency market. Fuel prices may be volatile and the price that can be risks, weather risk, and the market risk of outages. In order to obtained from power sales may not change at the same rate or manage these risks, we may enter into fixed-price derivative or in the same direction as changes in fuel costs. This could have a non-derivative contracts to hedge the variability in future cash material adverse impact on our financial results. flows from forecasted sales and purchases of energy, including:

" forward contracts, which commit us to purchase or sell Supply and Demand Risk energy commodities in the future; We are exposed to the risk that available sources of supply may " futures contracts, which are exchange-traded differ from the amount of power demanded by our customers standardized commitments to purchase or sell a under fixed-price load-serving contracts. During periods of high commodity or financial instrument, or to make a cash demand, our power supplies may be insufficient to serve our settlement, at a specific price and future date; customers' needs and could require us to purchase additional " swap agreements, which require payments to or from energy at higher prices. Alternatively, during periods of low counterparties based upon the differential between two demand, our power supplies may exceed our customers' needs prices for a predetermined contractual (notional) and could result in us selling that excess energy at lower prices. quantity; and Either of those circumstances could have a negative impact on " option contracts, which convey the right to buy or sell a our financial results. commodity, financial instrument, or index at a We are also exposed to variations in the prices and required predetermined price.

volumes of natural gas and coal we burn at our power plants to The objectives for entering into such hedges include:

generate electricity. During periods of high demand on our

• fixing the price for a portion of anticipated future generation assets, our fuel supplies may be insufficient and could electricity sales at a level that provides an acceptable require us to procure additional fuel at higher prices. return on our electric generation operations, Alternatively, during periods of low demand on our generation " fixing the price of a portion of anticipated fuel assets, our fuel supplies may exceed our needs, and could result purchases for the operation of our power plants, in us selling the excess fuels at lower prices. Either of these

• fixing the price for a portion of anticipated energy circumstances will have a negative impact on our financial purchases to supply our load-serving customers, and results. " managing our exposure to interest rate risk and foreign currency exchange risks.

Operations Risk The portion of forecasted transactions hedged may vary Operations risk is the risk that a generating plant will not be based upon management's assessment of market, weather, available to produce energy and the risks related to physical operational, and other factors.

delivery of energy to meet our customers' needs. If one or more While some of the contracts we use to manage risk of our generating facilities is not able to produce electricity represent commodities or instruments for which prices are when required due to operational factors, we may have to forego available from external sources, other commodities and certain sales opportunities or fulfill fixed-price sales commitments contracts are not actively traded and are valued using other through the operation of other more costly generating facilities pricing sources and modeling techniques to determine expected or through the purchase of energy in the wholesale market at future market prices, contract quantities, or both. We use our higher prices. We purchase power from generating facilities we best estimates to determine the fair value of commodity and do not own. If one or more of those generating facilities were derivative contracts we hold and sell. These estimates consider unable to produce electricity 'due to operational factors, we may various factors including closing exchange and over-the-counter be forced to purchase electricity in the wholesale market at price quotations, time value, volatility factors, and credit higher prices. This could have a material adverse impact on our exposure. However, it is likely that future market prices could financial results.

• vary from those used in recording mark-to-market energy assets Our nuclear plants produce electricity at a relatively low and liabilities, and such variations could be material.

marginal cost. The Nine Mile Point and Ginna facilities each We measure the sensitivity of our wholesale marketing and sells 90% of output under unit-contingent power purchase risk management mark-to-market energy contracts to potential agreements (we have no obligation to provide power if the units changes in market prices using value at risk. Value at risk is a are not available) to the previous owners. However, if an statistical model that attempts to predict risk of loss based on 64

historical market price volatility. We calculate value at risk using mark-to-market energy assets and liabilities, including both a historical variance/covariance technique that models option trading and non-trading activities. We experienced higher value positions using a linear approximation of their value. at risk for the year ended December 31, 2005 compared to the Additionally, we estimate variances and correlation using year ended December 31, 2004, primarily due to higher historical commodity price changes over the most recent rolling commodity prices.

three-month period. Our value at risk calculation includes all The following table details our value at risk for the trading wholesale marketing and risk management mark-to-market portion of our wholesale marketing and risk management energy assets and liabilities, including contracts for energy mark-to-market energy assets and liabilities over a one-day commodities and derivatives that result in physical settlement holding period at a 99% confidence level for 2005 and 2004:

and contracts that require cash settlement.

The value at risk calculation does not include market risks Wholesale Trading Value at Risk associated with activities that are subject to accrual accounting, For the year ended December 31, 2005 2004 primarily our generating facilities and our competitive supply (In millions) load-serving activities. We manage these risks by monitoring our Average $ 5.5 $ 2.6 High 13.3 6.9 fuel and energy purchase requirements and our estimated contract sales volumes compared to associated supply We experienced higher value at risk for the year ended arrangements. We also engage in hedging activities to manage December 31, 2005 compared to the year ended December 31, these risks. We describe those risks and our hedging activities 2004, for the trading portion of our wholesale trading portfolio earlier in this section. due to increased commodity prices, volatility, and trading The value at risk amounts below represent the potential activity. Our trading positions can be used to manage the pre-tax loss in the fair value of our wholesale marketing and risk commodity price risk of our competitive supply activities and management mark-to-market energy assets and liabilities over our generation facilities. We also engage in trading activities for one and ten-day holding periods. profit. These activities are managed through daily value at risk and stop loss limits and liquidity guidelines.

Total Wholesale Value at Risk Due to the inherent limitations of statistical measures such For the year ended December 31, 2005 2004 as value at risk and the seasonality of changes in market prices, (In millions) the value at risk calculation may not reflect the full extent of 99% Confidence Level, One-Day Holding our commodity price risk exposure. Additionally, actual changes Period in the value of options may differ from the value at risk Year end $10.0 $ 4.4 calculated using a linear approximation inherent in our Average 6.1 3.7 High 14.5 7.8 calculation method. As a result, actual changes in the fair value Low 2.4 2.5 of mark-to-market energy assets and liabilities could differ from 95% Confidence Level, One-Day Holding the calculated value at risk, and such changes could have a Period material impact on our financial results.

Year end $ 7.6 $ 3.4 Average 4.7 2.8 Regulated Electric Business High 11.0 5.9 BGE's residential base rates are frozen for a six-year period Low 1.8 1.9 ending June 30, 2006, and its commercial and industrial base 95% Confidence Level, Ten-Day Holding rates were frozen for a four-year period that ended June 30, Period 2004. The commodity and transmission components of rates are Year end $24.1 $10.7 frozen for different time periods depending on the customer Average 14.7 9.0 type and service options selected by customers.

High 34.9 18.7 Our wholesale marketing and risk management operation Low 5.8 6.1 provides BGE 100% of the energy and capacity to meet its Based on a 99% confidence interval, we would expect a residential standard offer service obligations through June 30, one-day change in the fair value of the portfolio greater than or 2006. Bidding to supply BGE's standard offer service to equal to the daily value at risk approximately once in every commercial and industrial customers, and to residential 100 days. In 2005, we experienced one instance where the actual customers beyond June 30, 2006, will occur from time to time daily mark-to-market change in portfolio value exceeded the through a competitive bidding process approved by the predicted value at risk. On average, we expect to experience a Maryland PSC. Our wholesale marketing and risk management change in value to our portfolio greater than our value at risk operation is supplying a portion of BGE's standard offer service approximately three times in a calendar year. However, published obligation to commercial and industrial customers. We discuss market studies conclude that exceeding daily value at risk less standard offer service and the impact on base rates in more than seven times in a one-year period is considered consistent detail in Item 1. Business-ElectricBusiness section.

with a 99% confidence interval. BGE may receive performance assurance collateral from The table above is the value at risk associated with our suppliers to mitigate suppliers' credit risks in certain wholesale marketing and risk management operation's circumstances. Performance assurance collateral is designed to 65

protect BGE's potential exposure over the term of the supply Our exposure to unrated counterparties was $1.4 billion at contracts and will fluctuate to reflect changes in market prices. December 31, 2005 compared to $328 million at December 31, In addition to the collateral provisions, there are supplier 2004. This increase was mostly due to the growth in our "step-up" provisions, where other suppliers can step in if the merchant energy business, particularly with natural gas and early termination of a Full-Requirements Service Agreement with international coal customers that do not have public credit a supplier should occur, as well as specific mechanisms for BGE ratings. Although not rated, a majority of these counterparties to otherwise replace defaulted supplier contracts. All costs are considered investment grade equivalent based on our internal incurred by BGE to replace the supply contract are to be credit ratings. We utilize internal credit ratings to evaluate the recovered from the defaulting supplier or from customers creditworthiness of our wholesale customers, including those through rates. Finally, BGE's exposure to uncollectible expense companies that do not have public credit ratings. Based on or credit risk from customers for the commodity portion of the internal credit ratings, approximately $916 million or 68% of bill is covered by the administrative fee included in Provider of the exposure to unrated counterparties was rated investment Last Resort rates. grade equivalent at December 31, 2005 and approximately

$173 million or 53% was rated investment grade equivalent at Regulated Gas Business December 31, 2004. The following table provides the Our regulated gas business may enter into gas futures, options, breakdown of the credit quality of our wholesale credit portfolio and swaps to hedge its price risk under our market-based rate based on our internal credit ratings.

incentive mechanism and our off-system gas sales program. We discuss this further in Note 13. At December 31, 2005 and At December 31, 2005 2004 2004, our exposure to commodity price risk for our regulated Investment Grade Equivalent 80% 74%

gas business was not material. Non-Investment Grade 20 26 A portion of our total wholesale credit risk is related to Credit Risk transactions that are recorded in our Consolidated Balance We are exposed to credit risk, primarily through our merchant Sheets. These transactions primarily consist of open positions energy business. Credit risk is the loss that may result from from our wholesale marketing and risk management operation counterparties' nonperformance. We evaluate the credit risk of that are accounted for using mark-to-market accounting, as well our wholesale marketing and risk management operation and as amounts owed by wholesale counterparties for transactions our retail competitive supply activities separately as discussed that settled but have not yet been paid. The following table below.

highlights the credit quality and exposures related to these activities:

Wholesale CreditRisk We measure wholesale credit risk as the replacement cost for Number of Net open energy commodity and derivative transactions (both Total Counterparties Exposure of Exposure Greater Counterparties mark-to-market and accrual) adjusted for amounts owed to or Before than 10% Greater than Credit Credit Net of Net 10% of Net due from counterparties for settled transactions. The replacement Rating Collateral Collateral Exposure Exposure Exposure cost of open positions represents unrealized gains, net of any (Dollars in toiliorn) unrealized losses, where we have a legally enforceable right of Investment grade $1,465 $197 $1,268 1 $247 Split rating 39 15 24 - -

setoff. We monitor and manage the credit risk of our wholesale Non-investment marketing and risk management operation through credit grade 242 79 163 - -

policies and procedures which include an established credit Internally rated-investment grade 616 4 612 --

approval process, daily monitoring of counterparty credit limits, Internally rated-the use of credit mitigation measures such as margin, collateral, non-investment grade 209 13 196 - -

or prepayment arrangements, and the use of master netting agreements. Total $2,571 $308 $2,263 1 $247 As of December 31, 2005 and 2004, the credit portfolio of Our net exposure to investment grade counterparties and our wholesale marketing and risk management operation had the internally rated investment grade counterparties increased following public credit ratings: $977 million compared to December 31, 2004 primarily as a At December 31, 2005 2004 result of higher commodity prices.

Due to the possibility of extreme volatility in the prices of Rating energy commodities and derivatives, the market value of Investment Grade' 53% 62% contractual positions with individual counterparties could exceed Non-Investment Grade 7 15 established credit limits or collateral provided by those Not Rated 40 23 counterparties. If such a counterparty were then to fail to 1 Includes counterparties with an investment grade rating by at perform its obligations under its contract (for example, fail to least one of the major credit rating agencies. If split rating exists, deliver the electricity our wholesale marketing and risk the lower rating is used.

management operation had contracted for), we could incur a loss that could have a material impact on our financial results.

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Additionally, if a counterparty were to default and we were Foreign Currency Risk to liquidate all contracts with that entity, our credit loss would Our merchant energy business is exposed to the impact of include the loss in value of mark-to-market contracts, the foreign exchange rate fluctuations. This foreign currency risk amount owed for settled transactions, and additional payments, arises from our activities in countries where we transact in if any, that we would have to make to settle unrealized losses on currencies other than the U.S. dollar. In 2005, our exposure to accrual contracts. foreign currency risk was not material. However, we expect our foreign currency exposure to grow due to our Canadian presence Retail Credit Risk and international coal operations. We manage our exposure to We are exposed to retail credit risk through our competitive foreign currency exchange rate risk using a comprehensive electricity and natural gas supply activities which serve foreign currency hedging program. While we cannot predict commercial and industrial companies. Retail credit risk results currency fluctuations, the impact of foreign currency exchange when customers default on their contractual obligations. This rate risk could be material.

risk represents the loss that may be incurred due to the nonpayment of a customer's accounts receivable balance, as well Equity Price Risk as the loss from the resale of energy previously committed to We are exposed to price fluctuations in equity markets primarily serve the customer. through our pension plan assets, our nuclear decommissioning Retail credit risk is managed through established credit trust funds, and trust assets securing certain executive benefits.

policies, monitoring customer exposures, and the use of credit We are required by the NRC to maintain externally funded mitigation measures such as letters of credit or prepayment trusts for the costs of decommissioning our nuclear power arrangements. plants. We discuss our nuclear decommissioning trust funds in Our retail credit portfolio is well diversified with no more detail in Note 1.

significant company or industry concentrations. During 2005, A hypothetical 10% decrease in equity prices would result we did not experience a material change in the credit quality of in an approximate $115 million reduction in the fair value of our retail credit portfolio compared to 2004. Retail credit quality our financial investments that are classified as trading or is dependent on the economy and the ability of our customers available-for-sale securities. In 2005, our actual return on to manage through unfavorable economic cycles and other pension plan assets was $76 million due to advances in the market changes. If the business environment were to be markets in which plan assets are invested. We describe our negatively affected by changes in economic or other market financial investments in more detail in Note 4, and our pension conditions, our retail credit risk may be adversely impacted. plans in Note 7.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk The information required by this item with respect to market risk is set forth in Item 7 of Part 1I of this Form 10-K under the heading Market Risk.

67

Item 8. Financial Statements and Supplementary Data REPORT2]

• OF]; IMANAGEMENT:l~

FinancialStatements accordance with generally accepted accounting principles in the The management of Constellation Energy Group, Inc. and United States of America.

Baltimore Gas and Electric Company (the "Companies") is The management of Constellation Energy conducted an responsible for the information and representations in the evaluation of the effectiveness of Constellation Energy's internal Companies' financial statements. The Companies prepare the control over financial reporting using the framework in Internal financial statements in accordance with accounting principles Control-Integrated Framework issued by the Committee of generally accepted in the United States of America based upon Sponsoring Organizations of the Treadway Commission available facts and circumstances and management's best (COSO). As noted in the COSO framework, an internal control estimates and judgments of known conditions. system, no matter how well conceived and operated, can provide PricewaterhouseCoopers LLP, an independent registered only reasonable-not absolute-assurance to management and the public accounting firm, has audited the financial statements and Board of Directors regarding achievement of an entity's financial expressed their opinion on them. They performed their audit in reporting objectives. Based upon the evaluation under this accordance with the standards of the Public Company framework, management concluded that Constellation Energy's Accounting Oversight Board (United States). internal control over financial reporting was effective as of The Audit Committee of the Board of Directors, which December 31, 2005.

consists of three independent Directors, meets periodically with PricewaterhouseCoopers LLP, an independent registered management, internal auditors, and PricewaterhouseCoopers LLP public accounting firm, has audited management's assessment of to review the activities of each in discharging their the effectiveness of Constellation Energy's internal control over responsibilities. The internal audit staff and financial reporting at December 31, 2005, as stated in their PricewaterhouseCoopers LLP have free access to the Audit report set forth below.

Committee. As discussed in Item 9A. Controls and Procedures, the management of Baltimore Gas & Electric Company ("BGE")

Management's Report on Internal Control Over has not assessed the effectiveness of BGE's internal control over FinancialReporting financial reporting on a standalone basis because it is not yet The management of Constellation Energy Group, Inc. required to do so by applicable federal securities laws and

("Constellation Energy"), under the direction of its principal regulations.

executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rule 13a-15(f).

r AShattuck III E. Follin Smith Constellation Energy's system of internal control over Chairman of the Board, Executive Vice-President, financial reporting is designed to provide reasonable assurance to Presidentand Chief ChiefFinancialOfficer, and Constellation Energy's management and Board of Directors Executive Officer ChiefAdministrative Officer regarding the reliability of financial reporting and the preparation of financial statements for external purposes in REPRT OF INEEDN REITEE PU3I CONIGFR To the Board ofDirectors and Shareholdersof Consolidated financial statements and financial Constellation Energy Group, Inc. statement schedule We have completed integrated audits of Constellation Energy In our opinion, the consolidated financial statements listed in Group, Inc. and Subsidiaries' 2005 and 2004 consolidated the index appearing under Item 15(a) 1 present fairly, in all financial statements and of its internal control over financial material respects, the financial position of Constellation Energy reporting as of December 31, 2005, and an audit of its 2003 Group, Inc. and Subsidiaries (the Company) at December 31, consolidated financial statements in accordance with the 2005 and 2004, and the results of their operations and their standards of the Public Company Accounting Oversight Board cash flows for each of the three years in the period ended (United States). Our opinions on Constellation Energy December 31, 2005 in conformity with accounting principles Group Inc.'s 2005, 2004, and 2003 consolidated financial generally accepted in the United States of America. In addition, statements and on its internal control over financial reporting as in our opinion, the financial statement schedule listed in the of December 31, 2005, based on our audits, are presented index appearing under Item 15(a) 2 presents fairly, in all below. material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial 68

statements and financial statement schedule based on our audits. standards require that we plan and perform the audit to obtain We conducted our audits of these statements in accordance with reasonable assurance about whether effective internal control over the standards of the Public Company Accounting Oversight financial reporting was maintained in all material respects. An Board (United States). Those standards require that we plan and audit of internal control over financial reporting includes perform the audit to obtain reasonable assurance about whether obtaining an understanding of internal control over financial the financial statements are free of material misstatement. An reporting, evaluating management's assessment, testing and audit of financial statements includes examining, on a test basis, evaluating the design and operating effectiveness of internal evidence supporting the amounts and disclosures in the financial control, and performing such other procedures as we consider statements, assessing the accounting principles used and necessary in the circumstances. We believe that our audit significant estimates made by management, and evaluating the provides a reasonable basis for our opinions.

overall financial statement presentation. We believe that our A company's internal control over financial reporting is a audits provide a reasonable basis for our opinion. process designed to provide reasonable assurance regarding the As discussed in Note I to the consolidated financial reliability of financial reporting and the preparation of financial statements, in 2005 the Company changed its method of statements for external purposes in accordance with generally accounting for conditional asset retirement obligations and the accepted accounting principles. A company's internal control accounting for stock based compensation. As discussed in Note I over financial reporting includes those policies and procedures to the consolidated financial statements, in 2003 the Company that (i) pertain to the maintenance of records that, in reasonable changed its method of accounting for asset retirement detail, accurately and fairly reflect the transactions and obligations and the accounting for certain energy contracts. dispositions of the assets of the company; (ii) provide reasonable We have also previously audited, in accordance with the assurance that transactions are recorded as necessary to permit standards of the Public Company Accounting Oversight Board preparation of financial statements in accordance with generally (United States), the consolidated balance sheets and statements accepted accounting principles, and that receipts and of capitalization of Constellation Energy Group, Inc. and expenditures of the company are being made only in accordance Subsidiaries as of December 31, 2003, 2002 and 2001, and the with authorizations of management and directors of the related consolidated statements of income, cash flows, and company; and (iii) provide reasonable assurance regarding common shareholders' equity and comprehensive income for the prevention or timely detection of unauthorized acquisition, use, years ended December 31, 2002 and 2001 (none of which are or disposition of the company's assets that could have a material presented herein); and we expressed unqualified opinions on effect on the financial statements.

those consolidated financial statements. In our opinion, the Because of its inherent limitations, internal control over information set forth in the Summary of Operations and financial reporting may not prevent or detect misstatements.

Summary of Financial Condition of Constellation Energy Also, projections of any evaluation of effectiveness to future Group, Inc. and Subsidiaries included in the Selected Financial periods are subject to the risk that controls may become Data for each of the rive years in the period ended inadequate because of changes in conditions, or that the degree December 31, 2005, is fairly stated, in all material respects, in of compliance with the policies or procedures may deteriorate.

relation to the consolidated financial statements from which it has been derived.

Internal control over financial reporting PricewaterhouseCoopers LLP Also, in our opinion, management's assessment, included in Baltimore, Maryland Management's Report on Internal Control Over Financial March 1, 2006 Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as To Board of Directorsand Shareholder ofBaltimore Gas and of December 31, 2005, based on criteria established in Internal Electric Company Control-IntegratedFramework issued by the Committee of In our opinion, the consolidated financial statements listed in Sponsoring Organizations of the Treadway Commission the index appearing under Item 15(a) 1 present fairly, in all (COSO), is fairly stated, in all material respects, based on those material respects, the financial position of Baltimore Gas and criteria. Furthermore, in our opinion, the Company maintained, Electric Company and Subsidiaries (the Company) at in all material respects, effective internal control over financial December 31, 2005 and 2004, and the results of their reporting as of December 31, 2005, based on criteria established operations and their cash flows for each of the three years in the in Internal Control-IntegratedFramework issued by the COSO. period ended December 31, 2005 in conformity with accounting The Company's management is responsible for maintaining principles generally accepted in the United States of America. In effective internal control over financial reporting and for its addition, in our opinion, the financial statement schedule listed assessment of the effectiveness of internal control over financial in the index appearing under Item 15(a) 2 presents fairly, in all reporting. Our responsibility is to express opinions on material respects, the information set forth therein when read in managements assessment and on the effectiveness of the conjunction with the related consolidated financial statements.

Company's internal control over financial reporting based on our These financial statements and financial statement schedule are audit. We conducted our audit of internal control over financial the responsibility of the Companys management. Our reporting in accordance with the standards of the Public responsibility is to express an opinion on these financial Company Accounting Oversight Board (United States). Those statements and financial statement schedule based on our audits.

69

We conducted our audits of these statements in accordance with 2003, 2002 and 2001, and the related consolidated statements the standards of the Public Company Accounting Oversight of income, cash flows, and comprehensive income for the years Board (United States). Those standards require that we plan and ended December 31, 2002 and 2001 (none of which are perform the audit to obtain reasonable assurance about whether presented herein); and we expressed unqualified opinions on the financial statements are free of material misstatement. An those consolidated financial statements. In our opinion, the audit includes examining, on a test basis, evidence supporting information set forth in the Summary of Operations and the amounts and disclosures in the financial statements, assessing Summary of Financial Condition of Baltimore Gas and Electric the accounting principles used and significant estimates made by Company and Subsidiaries included in the Selected Financial management, and evaluating the overall financial statement Data for each of the five years in the period ended presentation. We believe that our audits provide a reasonable December 31, 2005, is fairly stated, in all material respects, in basis for our opinion. relation to the consolidated financial statements from which it As discussed in Note I to the consolidated financial has been derived.

statements, in 2003 the Company changed its method of accounting for asset retirement obligations.

We have also previously audited, in accordance with the standards of the Public Company Accounting Oversight Board PricewaterhouseCoopers LLP (United States), the consolidated balance sheets of Baltimore Gas Baltimore, Maryland and Electric Company and Subsidiaries as of December 31, March 1, 2006 70

CONSOLIDATED IA..E S NS Oo INC E Constellation Energy Group, Inc. and Subsidiaries Year Ended December 31, 2005 2004 2003 (In millions, except per share amounts)

Revenues Nonregulated revenues $14,133.8 $ 9,563.7 $6,819.9 Regulated electric revenues 2,036.5 1,967.6 1,921.5 Regulated gas revenues 961.7 755.1 712.7 Total revenues 17,132.0 12,286.4 9,454.1 Expenses Fuel and purchased energy expenses 13,246.7 8,699.9 6,142.3 Operating expenses 1,918.9 1,736.8 1,542.7 Merger-related transaction costs 17.0 - -

Workforce reduction costs 4.4 9.7 2.1 Depreciation, depletion, and amortization 542.2 505.7 453.9 Accretion of asset retirement obligations 62.1 53.2 42.7 Taxes other than income taxes 282.6 255.9 247.3 Total expenses 16,073.9 11,261.2 8,431.0 Income from Operations 1,058.1 1,025.2 1,023.1 Other Income 62.8 25.3 20.7 Fixed Charges Interest expense 306.9 324.4 336.6 Interest capitalized and allowance for borrowed funds used during construction (10.0) (10.8) (13.3)

BGE preference stock dividends 13.2 13.2 13.2 Total fixed charges 310.1 326.8 336.5 Income from Continuing Operations Before Income Taxes 810.8 723.7 707.3 Income Tax Expense 204.1 156.9 250.6 Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles 606.7 566.8 456.7 Income (loss) from discontinued operations, net of income taxes of $21.4,

$(11.2), $18.9, respectively 23.6 (27.1) 19.0 Cumulative effects of changes in accounting principles, net of income taxes of $(4.7) and $(119.5), respectively (7.2) - (198.4)

Net Income $ 623.1 $ 539.7 $ 277.3 Earnings Applicable to Common Stock $ 623.1 $ 539.7 $ 277.3 Average Shares of Common Stock Outstanding-Basic 177.5 172.1 166.3 Average Shares of Common Stock Outstanding-Diluted 179.7 173.1 166.7 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles-Basic $ 3.42 $ 3.30 $ 2.75 Income (loss) from discontinued operations 0.13 (0.16) 0.11 Cumulative effects of changes in accounting principles (0.04) - (1.19)

Earnings Per Common Share-Basic $ 3.51 $ 3.14 $ 1.67 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles-Diluted $ 3.38 $ 3.28 $ 2.74 Income (loss) from discontinued operations 0.13 (0.16) 0.11 Cumulative effects of changes in accounting principles (0.04) - (1.19)

Earnings Per Common Share-Diluted $ 3.47 $ 3.12 $ 1.66 Dividends Declared Per Common Share $ 1.34 $ 1.14 $ 1.04 See Notes to ConsolidatedFinancialStatements.

Certain prior-yearamounts have been reclassifiedto conform with the currentyear'spresentation.

71

Constellation Energy Group, Inc. and Subsidiaries At December 31, 2005 2004 (In millions)

Assets Current Assets Cash and cash equivalents $ 813.0 $ 706.3 Accounts receivable (net of allowance for uncollectibles of $47.4 and $43.1, respectively) 2,727.9 1,979.3 Fuel stocks 489.5 298.3 Materials and supplies 197.0 203.8 Mark-to-marker energy assets 1,339.2 567.3 Risk management assets 1,244.3 471.5 Unamortized energy contract assets 55.6 37.2 Other 555.3 225.7 Total current assets 7,421.8 4,489.4 Investments and Other Assets Nuclear decommissioning trust funds 1,110.7 1,033.7 Investments in qualifying facilities and power projects 306.2 318.4 Regulatory assets (net) 154.3 195.4 Goodwill 147.1 144.8 Mark-to-market energy assets 1,089.3 359.8 Risk management assets 626.0 306.2 Unamortized energy contract assets 141.2 80.1 Other 410.6 332.7 Total investments and other assets 3,985.4 2,771.1 Property, Plant and Equipment Nonregulated property, plant and equipment 8,580.8 8,638.4 Regulated property, plant and equipment Plant in service 5,423.8 5,324.4 Construction work in progress 93.9 83.1 Plant held for future use 2.8 5.2 Total regulated property, plant and equipment 5,520.5 5,412.7 Nuclear fuel (net of amortization) 302.0 264.3 Accumulated depreciation (4,336.6) (4,228.8)

Net property, plant and equipment 10,066.7 10,086.6 Total Assets $21,473.9 $17,347.1 See Notes to ConsolidatedFinancialStatements.

Certain prior-yearamounts have been reclassified to conform with the currentyear'spresentation.

72

Constellation Energy Group, Inc. and Subsidiaries At December 31, 2005 2004 (In millions)

Liabilities and Equity Current Liabilities Short-term borrowings $ 0.7 $ -

Current portion of long-term debt 491.3 480.4 Accounts payable and accrued liabilities 1,667.9 1,424.9 Customer deposits and collateral 458.9 223.8 Mark-to-market energy liabilities 1,348.7 559.7 Risk management liabilities 483.5 304.3 Unamortized energy contract liabilities 489.5 67.2 Deferred income taxes 151.4 95.0 Accrued expenses and other 780.4 507.1 Total current liabilities 5,872.3 3,662.4 Deferred Credits and Other Liabilities Deferred income taxes 1,180.8 1,303.3 Asset retirement obligations 908.0 825.0 Mark-to-market energy liabilities 912.3 315.0 Risk management liabilities 1,035.5 472.2 Unamortized energy contract liabilities 1,118.7 86.2 Postretirement and postemployment benefits 382.6 375.3 Net pension liability 401.4 269.7 Deferred investment tax credits 64.1 71.2 Other 101.0 145.8 Total deferred credits and other liabilities 6,104.4 3,863.7 Capitalization (See Consolidated Statements of Capitalization)

Long-term debt 4,369.3 4,813.2 Minority interests 22.4 90.9 BGE preference stock not subject to mandatory redemption 190.0 190.0 Common shareholders' equity 4,915.5 4,726.9 Total capitalization 9,497.2 9,821.0 Commitments, Guarantees, and Contingencies (see Note 12)

Total liabilities and Equity $21,473.9 $17,347.1 See Notes to ConsolidatedFinancialStatements.

Certainprior-year amounts have been reclassified to conform with the current year! presentation.

73

Constellation Energy Group, Inc. and Subsidiaries Year Ended December 31, 2005 2004 2003 (In millions)

Cash Flows From Operating Activities Net income $ 623.1 $ 539.7 $ 277.3 Adjustments to reconcile to net cash provided by operating activities (Gain) loss on sales of discontinued operations (13.8) 50.1 Cumulative effects of changes in accounting principles 7.2 198.4 Depreciation, depletion, and amortization 603.0 646.8 596.4 Accretion of asset retirement obligations 62.1 53.2 42.7 Deferred income taxes 136.9 123.4 109.2 Investment tax credit adjustments (7.1) (7.2) (7.3)

Deferred fuel costs (11.9) 6.0 (10.1)

Pension and postemployment benefits 23.6 (3.0) (69.4)

Workforce reduction costs 4.4 9.7 2.1 Merger-related transaction costs 17.0 Other non-cash (income) expense included in earnings (12.2) 4.9 (25.6)

Equity in earnings of affiliates less than dividends received 38.7 29.5 38.4 Proceeds from derivative power sales contracts classified as financing activities under SFAS No. 149 (72.6)

Changes in Accounts receivable (961.2) (397.4) (282.6)

Mark-to-market energy assets and liabilities (88.4) (27.2) 14.9 Risk management assets and liabilities (27.5) (39.7) (92.9)

Materials, supplies, and fuel stocks (250.3) (112.1) (51.5)

Other current assets (277.1) 5.3 28.8 Accounts payable and accrued liabilities 282.8 260.2 193.5 Other current liabilities 546.4 (8.7) 139.8 Other 4.1 (46.7) (44.3)

Net cash provided by operating activities 627.2 1,086.8 1,057.8 Cash Flows From Investing Activities Investments in property, plant and equipment (760.0) (703.6) (635.7)

Contract and portfolio acquisitions (336.2) - -

Asset acquisitions and business combinations, net of cash acquired (237.2) (457.3) (546.6)

Investments in nuclear decommissioning trust fund securities (370.8) (424.2) (176.0)

Proceeds from nuclear decommissioning trust fund securities 353.2 402.2 162.8 Net proceeds from sale of discontinued operations 289.4 72.7 -

Issuances of loans receivable (82.8) - -

Sale of investments and other assets 14.4 36.1 148.8 Other investments (44.0) (78.6) (113.6)

Net cash used in investing activities (1,174.0) (1,152.7) (1,160.3)

Cash Flows From Financing Activities Net issuance (maturity) of short-term borrowings 10.7 (9.6) (0.9)

Proceeds from issuance of Common stock 96.9 293.9 95.4 Long-term debt 12.0 100.0 983.3 Repayment of long-term debt (362.3) (243.2) (707.5)

Common stock dividends paid (228.8) (189.7) (169.2)

Proceeds from contract and portfolio acquisitions 1,026.9 117.5 -

Proceeds from derivative power sales contracts classified as financing activities under SFAS No. 149 72.6 - -

Other 25.5 (18.0) 7.7 Net cash provided by financing activities 653.5 50.9 208.8 Net Increase (Decrease) in Cash and Cash Equivalents 106.7 (15.0) 106.3 Cash and Cash Equivalents at Beginning of Year 706.3 721.3 615.0 Cash and Cash Equivalents at End of Year $ 813.0 $ 706.3 $ 721.3 Other Cash Flow Information:

Cash paid during the year for:

Interest (net of amounts capitalized) $ 301.3 $ 327.9 $ 335.7 Income taxes $ 115.3 $ 203.9 $ 35.4 See Notes to ConsolidatedFinancialStatements.

Certainprior-year amounts have been reclassified to conform with the currentyears presentation.

74

Constellation Energy Group, Inc. and Subsidiaries Accumulated Other Common Stock Retained Comprehensive Total Year Ended December 31, 2005, 2004, and2003 Shares Amount Earnings Loss Amount (Dollar amounts in millions, number of shares in thousands)

Balance at December 31, 2002 164,843 $2,078.9 $1,977.6 $(194.2) $3,862.3 Comprehensive Income Net income 277.3 277.3 Other comprehensive income Reclassification of net gain on sales of securities from OCI to net income, net of taxes of $0.2 (0.4) (0.4)

Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $10.7 (16.4) (16.4)

Net unrealized gain on securities, net of taxes of $24.4 37.3 37.3 Net unrealized gain on hedging instruments, net of taxes of $15.8 39.9 39.9 Minimum pension liability, net of taxes of $8.2 12.6 12.6 Total Comprehensive Income 277.3 73.0 350.3 Common stock dividend declared ($1.04 per share) (172.8) (172.8)

Common stock issued 2,976 100.9 100.9 Other (0.2) (0.2)

Balance at December 31, 2003 167,819 2,179.8 2,081.9 (121.2) 4,140.5 Comprehensive Income Net income 539.7 539.7 Other comprehensive income Reclassification of net loss on securities from OCI to net income, net of taxes of $1.4 2.2 2.2 Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $169.0 (270.8) (270.8)

Net unrealized gain on securities, net of taxes of $22.2 33.7 33.7 Net unrealized gain on hedging instruments, net of taxes of $124.7 196.8 196.8 Net unrealized gain on foreign currency translation 0.4 0.4 Minimum pension liability, net of taxes of $27.9 (42.6) (42.6)

Total Comprehensive Income 539.7 (80.3) 459.4 Common stock dividend declared ($1.14 per share) (196.3) (196.3)

Common stock issued 8,514 322.7 322.7 Other 0.6 0.6 Balance at December 31, 2004 176,333 2,502.5 2,425.9 (201.5) 4,726.9 Comprehensive Income Net income 623.1 623.1 Other comprehensive income Reclassification of net gains on securities from OCI to net income, net of taxes of $1.2 (1.8) (1.8)

Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $492.2 (794.6) (794.6)

Net unrealized gain on securities, net of taxes of $15.7 23.8 23.8 Net unrealized gain on hedging instruments, net of taxes of $335.9 534.7 534.7 Net unrealized gain on foreign currency translation 1.0 1.0 Minimum pension liability, net of taxes of $50.4 (77.1) (77.1)

Total Comprehensive Income 623.1 (314.0) 309.1 Common stock dividend declared ($1.34 per share) (238.4) (238.4)

Common stock issued 1,968 118.3 118.3 Other (0.4) (0.4)

Balance at December 31, 2005 178,301 $2,620.8 $2,810.2 $(515.5) $4,915.5 See Notes to ConsolidatedFinancialStatements.

75

Constellation Energy Group, Inc. and Subsidiaries At December 31, 2005 2004 (In millions)

Long-Term Debt Long-term debt of Constellation Energy 77/% Notes, due April 1, 2005 $ - $ 300.0 6.35% Fixed-Rate Notes, due April 1,2007 600.0 600.0 6.125% Fixed-Rate Notes, due September 1, 2009 500.0 500.0 7.00% Fixed-Rate Notes, due April 1, 2012 700.0 700.0 4.55% Fixed-Rate Notes, due June 15, 2015 550.0 550.0 7.60% Fixed-Rate Notes, due April 1, 2032 700.0 700.0 Fair Value of Interest Rate Swaps (0.9) 13.3 Total long-term debt of Constellation Energy 3,049.1 3,363.3 Long-term debt of nonregulated businesses Tax-exempt debt transferred from BGE effective July 1, 2000 Pollution control loan, due July 1, 2011 - 36.0 36.0 Port facilities loan, due June 1, 2013 48.0 48.0 Pollution control loan, due July 1, 2014 20.0 20.0 5.55% Pollution control revenue refunding loan, due July 15, 2014 47.0 47.0 Economic development loan, due December 1, 2018 35.0 35.0 6.00% Pollution control revenue refunding loan, due April 1, 2024 75.0 75.0 Floating-rate pollution control loan, due June 1, 2027 8.8 8.8 District Cooling facilities loan, due December 1, 2031 25.0 25.0 Loans under revolving credit agreements 100.1 4.875% Inflation protection loan due February 15, 2012 12.0 5.00% Mortgage note, due July 5, 2010 12.8 4.25% Mortgage note, due March 15, 2009 1.9 2.3 South Carolina synthetic fuel facility loan, due January 15, 2008 36.0 40.0 Total long-term debt of nonregulated businesses 357.5 437.2 First Refunding Mortgage Bonds of BGE Remarketed floating-rate series, due September 1, 2006 97.4 99.3 7 1A% Series, due January 15, 2007 122.0 122.5 6YA% Series, due March 15, 2008 123.4 124.5 Total First Refunding Mortgage Bonds of BGE 342.8 346.3 Other long-term debt of BGE 5.25% Notes, due December 15, 2006 300.0 300.0 5.20% Notes, due June 15, 2033 200.0 200.0 Medium-term notes, Series B 12.0 12.1 Medium-term notes, Series D 10.0 48.0 Medium-term notes, Series E 199.5 199.5 Medium-term notes, Series G 140.0 140.0 Total other long-term debt of BGE 861.5 899.6 6.20% deferrable interest subordinated debentures due October 15, 2043 to BGE wholly owned BGE Capital Trust II relating to trust preferred securities 257.7 257.7 Unamortized discount and premium (8.0) (10.5)

Current portion of long-term debt (491.3) (480.4)

Total long-term debt $4,369.3 $4,813.2 See Notes to ConsolidatedFinancialStatements.

continuedon next page 76

Constellation Energy Group, Inc. and Subsidiaries At December31, 2005 2004 (In millions)

Minority Interests $ 22.4 $ 90.9 BGE Preference Stock Cumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized 7.125%, 1993 Series, 400,000 shares outstanding, callable at $102.85 per share until June 30, 2006, and at lesser amounts thereafter 40.0 40.0 6.97%, 1993 Series, 500,000 shares outstanding, callable at $102.79 per share until September 30, 2006, and at lesser amounts thereafter 50.0 50.0 6.70%, 1993 Series, 400,000 shares outstanding, callable at $102.68 per share until December 31, 2006, and at lesser amounts thereafter 40.0 40.0 6.99%, 1995 Series, 600,000 shares outstanding, callable at $103.50 per share until September 30, 2006, and at lesser amounts thereafter 60.0 60.0 Total preference stock not subject to mandatory redemption 190.0 190.0 Common Shareholders' Equity Common stock without par value, 250,000,000 shares authorized; 178,300,844 and 176,333,121 shares issued and outstanding at December 31, 2005 and 2004, respectively.

(At December 31, 2005, 3,695,418 shares were reserved for the long-term incentive plans, 7,918,412 shares were reserved for the Shareholder Investment Plan, 1,520,000 shares were reserved for the continuous offering programs, and 2,007,860 shares were reserved for the employee savings plan.) 2,620.8 2,502.5 Retained earnings 2,810.2 2,425.9 Accumulated other comprehensive loss (515.5) (201.5)

Total common shareholders' equity 4,915.5 4,726.9 Total Capitalization $9,497.2 $9,821.0 See Notes to ConsolidatedFinancialStatements.

77

Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2005 2004 2003 (In millions)

Revenues Electric revenues $2,036.5 $1,967.7 $1,921.6 Gas revenues 972.8 757.0 726.0 Total revenues 3,009.3 2,724.7 2,647.6 Expenses Operating Expenses Electricity purchased for resale 1,068.9 1,034.0 1,023.5 Gas purchased for resale 687.5 484.3 445.8 Operations and maintenance 450.2 427.8 406.2 Merger-relared transaction costs 5.4 - -

Workforce reduction costs - - 0.7 Depreciation and amortization 232.4 242.3 228.3 Taxes other than income taxes 168.4 164.9 158.1 Total expenses 2,612.8 2,353.3 2,262.6 Income from Operations 396.5 371.4 385.0 Other Income (Expense) 5.9 (6.4) (5.4)

Fixed Charges Interest expense 95.6 97.3 112.8 Allowance for borrowed funds used during construction (2.1) (1.1) (1.6)

Total fixed charges 93.5 96.2 111.2 Income Before Income Taxes 308.9 268.8 268.4 Income Taxes Current 122.6 69.4 48.5 Deferred (0.9) 34.9 58.5 Investment tax credit adjustments (1.8) (1.8) (1.8)

Total income taxes 119.9 102.5 105.2 Net Income 189.0 166.3 163.2 Preference Stock Dividends 13.2 13.2 13.2 Earnings Applicable to Common Stock $ 175.8 $ 153.1 $ 150.0 C O. A.R. O. . - I E Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2005 2004 2003 (In millions)

Net Income $ 175.8 $ 153.1 $ 150.0 Other comprehensive income Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $0.0 - (0.1) -

Unrealized gain on hedging instruments, net of taxes of $0.4 - - 0.8 Comprehensive Income $ 175.8 $ 153.0 $ 150.8 See Notes to ConsolidatedFinancialStatements 78

Baltimore Gas and Electric Company and Subsidiaries At December 31, 2005 2004 (In millions)

Assets Current Assets Cash and cash equivalents $ 15.1 $ 8.2 Accounts receivable (net of allowance for uncollectibles of $13.0 and $13.0, respectively) 480.5 381.8 Investment in cash pool, affiliated company - 127.9 Accounts receivable, affiliated companies 1.8 1.0 Fuel stocks 102.7 86.5 Materials and supplies 40.1 34.6 Prepaid taxes other than income taxes 45.7 44.5 Other 6.5 7.2 Total current assets 692.4 691.7 Investments and Other Assets Regulatory assets (net) 154.3 195.4 Receivable, affiliated company 154.7 150.4 Other 144.0 134.2 Total investments and other assets 453.0 480.0 Utility Plant Plant in service Electric 3,891.1 3,759.3 Gas 1,116.7 1,086.7 Common 416.0 478.4 Total plant in service 5,423.8 5,324.4 Accumulated depreciation (1,923.8) (1,921.5)

Net plant in service 3,500.0 3,402.9 Construction work in progress 93.9 83.1 Plant held for future use 2.8 5.2 Net utility plant 3,596.7 3,491.2 Total Assets $ 4,742.1 $ 4,662.9 See Notes to ConsolidatedFinancialStatements.

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Baltimore Gas and Electric Company and Subsidiaries At December 31, 2005 2004 (In millions) liabilities and Equity Current Liabilities Current portion of long-term debt $ 469.6 $ 165.9 Accounts payable and accrued liabilities 169.7 125.4 Accounts payable and accrued liabilities, affiliated companies 152.8 146.1 Borrowing from cash pool, affiliated company 3.2 -

Customer deposits 65.1 64.3 Accrued taxes 35.5 32.2 Accrued expenses and other 79.6 71.7 Total current liabilities 975.5 605.6 Deferred Credits and Other Liabilities Deferred income taxes 608.9 608.0 Postretirement and postemployment benefits 277.7 278.2 Deferred investment tax credits 15.1 16.9 Other 19.0 20.0 Total deferred credits and other liabilities 920.7 923.1 Long-term Debt First refunding mortgage bonds of BGE 342.8 346.3 Other long-term debt of BGE 861.5 899.6 6.20% deferrable interest subordinated debentures due October 15, 2043 to wholly owned BGE Capital Trust II relating to trust preferred securities 257.7 257.7 Long-term debt of nonregulated business 25.0 25.0 Unamortized discount and premium (2.3) (3.2)

Current portion of long-term debt (469.6) (165.9)

Total long-term debt 1,015.1 1,359.5 Minority Interest 18.3 18.7 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholder's Equity Common stock 912.2 912.2 Retained earnings 709.6 653.1 Accumulated other comprehensive income 0.7 0.7 Total common shareholder's equity 1,622.5 1,566.0 Commitments, Guarantees, and Contingencies (see Note 12)

Total Liabilities and Equity $ 4,742.1 $ 4,662.9 See Notes to ConsolidatedFinancialStatements.

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COSLIAE STTMET OF CAHFLW Baltimore Gas and Electric Company and Subsidiaries Year Ended December 31, 2005 2004 2003 (In millions)

Cash Flows From Operating Activities Net income $189.0 $ 166.3 $ 163.2 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 247.0 257.4 242.7 Deferred income taxes (0.9) 34.9 58.5 Investment tax credit adjustments (1.8) (1.8) (1.8)

Deferred fuel costs (11.9) 6.0 (10.1)

Pension and postemployment benefits (1.6) (16.6) (56.2)

Allowance for equity funds used during construction (3.9) (2.0) (3.0)

Workforce reduction costs 0.7 Changes in Accounts receivable (98.7) (27.0) 2.7 Receivables, affiliated companies (0.8) 3.5 126.7 Materials, supplies, and fuel stocks (21.7) (28.4) (20.3)

Other current assets (0.5) 1.0 (0.4)

Accounts payable and accrued liabilities 44.3 24.2 8.0 Accounts payable and accrued liabilities, affiliated companies 6.7 (5.6) 66.1 Other current liabilities 12.0 (10.3) 14.0 Other (37.4) (30.2) (22.9)

Net cash provided by operating activities 319.8 371.4 567.9 Cash Flows From Investing Activities Utility construction expenditures (exduding equity portion of allowance for funds used during construction) (270.5) (246.4) (269.0)

Change in cash pool at parent 131.1 102.3 107.9 Sales of investments and other assets 11.0 4.9 -

Other (10.4) 2.7 1.8 Net cash used in investing activities (138.8) (136.5) (159.3)

Cash Flows From Financing Activities Proceeds from issuance of long-term debt - - 439.4 Repayment of long-term debt (41.6) (149.8) (710.4)

Preference stock dividends paid (13.2) (13.2) (13.2)

Distribution to parent (119.3) (74.7) (124.8)

Other - - 1.2 Net cash used in financing activities (174.1) (237.7) (407.8)

Net Increase (Decrease) in Cash and Cash Equivalents 6.9 (2.8) 0.8 Cash and Cash Equivalents at Beginning of Year 8.2 11.0 10.2 Cash and Cash Equivalents at End of Year $ 15.1 $ 8.2 $ 11.0 Other Cash Flow Information:

Cash paid during the year for:

Interest (net of amounts capitalized) $ 88.6 $ 95.5 $120.6 Income taxes $123.3 $ 80.7 $ 24.7 See Notes to ConsolidatedFinancialStatements.

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Notes to Consolidated Financial Statements I Significant Accounting Policies Nature of Our Business The Equity Method Constellation Energy Group, Inc. (Constellation Energy) is an We usually use the equity method to report investments, energy company that conducts its business through various corporate joint ventures, partnerships, and affiliated companies subsidiaries including a merchant energy business and Baltimore (including qualifying facilities and power projects) where we Gas and Electric Company (BGE). Our merchant energy hold a 20% to 50% voting interest. Under the equity method, business is a competitive provider of energy solutions for a we report:

variety of customers. BGE is a regulated electric transmission " our interest in the entity as an investment in our and distribution utility company and a regulated gas distribution Consolidated Balance Sheets, and utility company with a service territory that covers the City of " our percentage share of the earnings from the entity in Baltimore and all or part of ten counties in central Maryland. our Consolidated Statements of Income.

We describe our operating segments in Note 3. The only time we do not use this method is if we can This report is a combined report of Constellation Energy exercise control over the operations and policies of the company.

and BGE. References in this report to "we" and "our" are to If we have control, accounting rules require us to use Constellation Energy and its subsidiaries. References in this consolidation.

report to the "regulated business(es)" are to BGE.

The Cost Method Pending Merger with FPL Group, Inc. We usually use the cost method if we hold less than a 20%

In December 2005, Constellation Energy entered into an voting interest in an investment. Under the cost method, we agreement and plan of merger with FPL Group, Inc. (FPL report our investment at cost in our Consolidated Balance Group). We discuss the pending merger in more detail in Sheets. The only time we do not use this method is when we Note 15. can exercise significant influence over the operations and policies of the company. If we have significant influence, accounting Consolidation Policy rules require us to use the equity method.

We use three different accounting methods to report our investments in our subsidiaries or other companies: Regulation of Electric and Gas Business consolidation, the equity method, and the cost method. The Maryland Public Service Commission (Maryland PSC) and the Federal Energy Regulatory Commission (FERC) provide the Consolidation final determination of the rates we charge our customers for our We use consolidation for two types of entities: regulated businesses. Generally, we use the same accounting

" subsidiaries (other than variable interest entities) in policies and practices used by nonregulated companies for which we own a majority of the voting stock, and financial reporting under accounting principles generally

" variable interest entities (VIEs) for which we are the accepted in the United States of America. However, sometimes primary beneficiary. Financial Accounting Standards the Maryland PSC or the FERC orders an accounting treatment Board (FASB) Interpretation No. (FIN) 46R, different from that used by nonregulated companies to Consolidation of VariableInterest Entities, requires us to determine the rates we charge our customers.

use consolidation when we are the primary beneficiary When this happens, we must defer (include as an asset or of a VIE, which means that we have a controlling liability in our, and BGE's, Consolidated Balance Sheets and financial interest in a VIE. We discuss our investments exclude from our, and BGE's, Consolidated Statements of in VIEs in more detail in Note 4. Income) certain regulated business expenses and income as Consolidation means that we combine the accounts of these regulatory assets and liabilities. We have recorded these entities with our accounts. Therefore, our consolidated financial regulatory assets and liabilities in our, and BGE's, Consolidated statements include our accounts, the accounts of our majority- Balance Sheets in accordance with Statement of Financial owned subsidiaries that are not VIEs, and the accounts of VIEs Accounting Standards (SFAS) No. 71, Accountingfor the Effects for which we are the primary beneficiary. We have not of Certain T3pes ofRegulation.

consolidated any entities for which we do not have a controlling We summarize and discuss our regulatory assets and voting interest. We eliminate all intercompany balances and liabilities further in Note 6.

transactions when we consolidate these accounts.

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Use of Accounting Estimates During 2005, we terminated or restructured several Management makes estimates and assumptions when preparing in-the-money contracts in exchange for upfront cash payments financial statements under accounting principles generally and a reduction or cancellation of future performance accepted in the United States of America. These estimates and obligations. The termination or restructuring of two contracts assumptions affect various matters, including: allowed us to lower our exposure to performance risk under

" our reported amounts of revenues and expenses in our these contracts, and resulted in the realization of $77.0 million Consolidated Statements of Income during the reporting of pre-tax earnings in 2005 that would have been recognized periods, over the life of these contracts.

" our reported amounts of assets and liabilities in our Consolidated Balance Sheets at the dates of the financial Mark-to-Mfarket Accounting statements, and We record revenues using the mark-to-market method of

• our disclosure of contingent assets and liabilities at the accounting for derivative contracts for which we are not permitted dates of the financial statements. to use accrual accounting or hedge accounting. We discuss our use These estimates involve judgments with respect to of hedge accounting in the Derivatives and Hedging Activities numerous factors that are difficult to predict and are beyond section later in this Note. These mark-to-market activities include management's control. As a result, actual amounts could derivative contracts for energy and other energy-related materially differ from these estimates. commodities. Under the mark-to-market method of accounting, we record the fair value of these derivatives as mark-to-market Reclassifications energy assets and liabilities at the time of contract execution.

We have reclassified certain prior-year amounts for comparative Our wholesale marketing and risk management operation records purposes. These reclassifications did not affect consolidated net changes in mark-to-market energy assets and liabilities on a net income for the years presented. basis in "Nonregulated revenues" in our Consolidated Statements of Income. Our retail competitive supply operation records Revenues changes in sale contracts accounted for as mark-to-market in AccrualAccounting "Nonregulated revenues" in our Consolidated Statements of We record revenues from the sale of energy, energy-related Income.

products, and energy services under the accrual method of Mark-to-market energy assets and liabilities consist of accounting in the period when we deliver energy commodities or derivative contracts. While some of these contracts represent products, render services, or settle contracts. We use accrual commodities or instruments for which prices are available from accounting for our merchant energy and other nonregulated external sources, other commodities and certain contracts are not business transactions, including the generation or purchase and actively traded and are valued using modeling techniques to sale of electricity, gas, and coal as part of our physical delivery determine expected future market prices, contract quantities, or activities and for power, gas, and coal sales contracts that are not both. The market prices and quantities used to determine fair subject to mark-to-market accounting. Sales contracts that are value reflect management's best estimate considering various eligible for accrual accounting include non-derivative transactions factors, including closing exchange and over-the-counter and derivatives that qualify for and are designated as normal quotations, time value, and volatility factors. However, future purchases and normal sales of commodities that will be market prices and actual quantities will vary from those used in physically delivered. We record accrual revenues, including recording mark-to-market energy assets and liabilities, and it is settlements with independent system operators, on a gross basis possible that such variations could be material.

because we are a principal to the transaction and otherwise meet Mark-to-market revenues include:

the requirements of Emerging Issues Task Force (EITF) 03-11,

• gains or losses on new transactions at origination to the Reporting Gains and Losses on Derivative Instruments That Are extent permitted by applicable accounting rules, Subject to FASB Statement No. 133, Accountingfor Derivative

• unrealized gains and losses from changes in the fair Instruments and HedgingActivities, and Not Heldfor Trading value of open contracts, Purposes, and EITF 99-19, Reporting Revenue Gross as a Principal

• net gains and losses from realized transactions, and versus Net as an Agent.

• changes in valuation adjustments.

We may make or receive cash payments at the time we Origination gains, which are included in mark-to-market assume a power sale agreement for which the contract price revenues, arise primarily from contracts that our wholesale differs from current market prices. We recognize the cash marketing and risk management operation structures to meet the payment at inception in our Consolidated Balance Sheets as an risk management needs of our customers. Transactions that "Unamortized energy contract" asset or liability. We amortize result in origination gains may be unique and provide the these assets and liabilities into revenues based on the expected potential for individually significant gains from a single cash flows provided by the contracts. transaction.

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Origination gains represent the initial fair value recognized

• Credit-spread adjustment-for risk management on these structured transactions. The recognition of origination purposes we compute the value of our mark-to-market gains is dependent on the existence of observable market data energy assets and liabilities using a risk-free discount that validates the initial fair value of the contract. Origination rate. In order to compute fair value for financial gains were: reporting purposes, we adjust the value of our

• $61.6 million pre-tax in 2005, mark-to-market energy assets to reflect the credit-

• $19.7 million pre-tax in 2004, and worthiness of each customer (counterparty) based upon

• $62.3 million pre-tax in 2003. either published credit ratings, or equivalent internal Origination gains arose primarily from: credit ratings and associated default probability

• 6 transactions completed in 2005, one of which percentages. We compute this adjustment by applying contributed approximately $35 million pre-tax, the appropriate default probability percentage to our

• 7 transactions completed in 2004, of which no transaction outstanding credit exposure, net of collateral, for each contributed in excess of $10 million pre-tax, and counterparty. The level of this adjustment increases as

• 14 transactions completed in 2003, of which one our credit exposure to counterparties increases, the transaction contributed approximately $10 million pre-tax. maturity terms of our transactions increase, or the credit ratings of our counterparties deteriorate, and it decreases Valuation Adjustments when our credit exposure to counterparties decreases, We record valuation adjustments to reflect uncertainties the maturity terms of our transactions decrease, or the associated with certain estimates inherent in the determination credit ratings of our counterparties improve.

of the fair value of mark-to-market energy assets and liabilities.

To the extent possible, we utilize market-based data together FinancialStatement Presentation with quantitative methods for both measuring the uncertainties In the first quarter of 2003, we adopted EITF 02-3, Issues for which we record valuation adjustments and determining the Involved in Accounting for Derivative Contracts Heldfr Trading level of such adjustments and changes in those levels. Purposesand Contracts Involved in Energy Trading and Risk We describe below the main types of valuation adjustments Management Activities, which required the accrual method of we record and the process for establishing each. Generally, accounting for energy contracts that are not derivatives and increases in valuation adjustments reduce our earnings, and clarified when gains and losses can be recognized at the decreases in valuation adjustments increase our earnings. inception of derivative contracts, and recognized a However, all or a portion of the effect on earnings of changes in $430.0 million pre-tax, or $266.1 million after-tax, charge as a valuation adjustments may be offset by changes in the value of cumulative effect of change in accounting principle. The the underlying positions. contracts that were subject to the requirements of EITF 02-3

• Close-out adjustment-represents the estimated cost to were primarily our full requirements load-serving contracts and dose out or sell to a third-party open mark-to-market unit-contingent power purchase contracts, which are not positions. This valuation adjustment has the effect of derivatives.

valuing "long" positions (the purchase of a commodity) at Certain transactions entered into under master agreements the bid price and "short" positions (the sale of a and other arrangements provide our merchant energy business commodity) at the offer price. We compute this with a right of setoff in the event of bankruptcy or default by adjustment based on our estimate of the bid/offer spread the counterparty. We report such transactions net in our for each commodity and option price and the absolute Consolidated Balance Sheets in accordance with FASB quantity of our nrt open positions for each year. The Interpretation No. 39, Offietting ofAmounts Related to Certain level of total dose-out valuation adjustments increases as Contracts.

we have larger unhedged positions, bid-offer spreads increase, or market information is not available, and it Equity in Earnings decreases as we reduce our unhedged positions, bid-offer We include equity in earnings from our investments in spreads decrease, 6r market information becomes qualifying facilities and power projects in "Nonregulated available. To the extent that we are not able to obtain revenues" in our Consolidated Statements of Income in the observable marketý information for similar contracts, the period they are earned.

close-out adjustment is equivalent to the initial contract margin, thereby r&ording no gain or loss at inception. In the absence of observable market information, there is a presumption that the transaction price is equal to the market value of the contract, and therefore we do not recognize a gain or loss at inception. We recognize such gains or losses in Eamings as we realize cash flows under the contract or when observable market data becomes available.

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Fuel and Purchased Energy Expenses In accordance with the POLR settlement agreement We incur costs for approved by the Maryland PSC, BGE defers the difference

" the fuel we use to generate electricity, between certain of its actual costs related to the electric

" purchases of electricity from others, and commodity and what it collects from customers under the

" natural gas and coal that we resell. commodity charge in a given period. BGE either bills or refunds These costs are included in "Fuel and purchased energy its customers the difference in the future.

expenses" in our Consolidated Statements of Income. We discuss BGE's obligation to provide market-based standard offer certain of these separately below. We also include certain service to its largest commercial and industrial customers expired non-fuel direct costs, such as ancillary services, transmission May 31, 2005. BGE continues to provide an hourly-priced costs, and brokerage fees in "Fuel and purchased energy market-based standard offer service to those customers.

expenses" in our Consolidated Statements of Income.

Our retail competitive supply operation records changes in Regulated Gas purchase contracts accounted for as mark-to-market in "Fuel and BGE charges its gas customers for the natural gas they purchase purchased energy expenses" in our Consolidated Statements of from BGE using "gas cost adjustment clauses" set by the Income. Maryland PSC. Under these clauses, BGE defers the difference between certain of its actual costs related to the gas commodity Fuel Used to GenerateElectricity and Purchases of and what it collects from customers under the commodity ElectricityFrom Others charge in a given period. BGE either bills or refunds its NonredulatedBusinesses customers the difference in the future. The Maryland PSC We assemble a variety of power supply resources, including approved a modification of the gas cost adjustment clauses to baseload, intermediate, and peaking plants that we own, as well provide a market-based rates incentive mechanism. Under the as a variety of power supply contracts that may have similar market-based rates incentive mechanism, BGE's actual cost of characteristics, in order to enable us to meet our customers' gas is compared to a market index (a measure of the market energy requirements, which vary on an hourly basis. We price of gas in a given period). The difference between BGE's purchase power when our load-serving requirements exceed the actual cost and the market index is shared equally between amount of power available from our supply resources or when it shareholders and customers. Effective November 2001, the is more economic to do so than to operate our power plants. Maryland PSC approved a settlement that modifies certain The amount of power purchased depends on a number of provisions of the market-based rates incentive mechanism. These factors, including the capacity and availability of our power provisions require that BGE secure fixed-price contracts for at plants, the level of customer demand, and the relative economics least 10%, but not more than 20%, of forecasted system supply of generating power versus purchasing power from the spot requirements for the November through March period. These market. fixed-price contracts are not subject to sharing under the market-We also have acquired contracts and certain power purchase based rates incentive mechanism.

agreements that qualify as operating leases. Under these operating leases, we record fuel and purchased energy expense as Derivatives and Hedging Activities we make fixed capacity payments, as well as variable payments We are exposed to market risk, including changes in interest based on the actual output of the plants. rates and the impact of market fluctuations in the price and We may make or receive cash payments at the time we transportation costs of electricity, natural gas, and other acquire a contract or assume a power purchase agreement when commodities as discussed further in Note 13. In order to manage the contract price differs from market prices at dosing. We these risks, we use both derivative and non-derivative contracts recognize the cash payment or receipt at inception in our that may provide for settlement in cash or by delivery of a Consolidated Balance Sheets as an "Unamortized energy commodity, including:

contract" asset (payment) or liability (receipt). We amortize these " forward contracts, which commit us to purchase or sell assets and liabilities into fuel and purchased energy expenses energy commodities in the future, based on the expected cash flows provided by the contracts.

• futures contracts, which are exchange-traded standardized commitments to purchase or sell a Regulated Electric commodity or financial instrument, or to make a cash BGE is obligated to provide market-based standard offer service settlement, at a specific price and future date, to residential customers from July 1, 2006 through May 31, " swap agreements, which require payments to or from 2010, and for commercial and industrial customers for varying counterparties based upon the differential between two periodsbeyond June 30, 2004. depending on customer load. prices for a predetermined contractual (notional)

The Provider of Last Resort (POLR) rates charged during these quantity, and time periods will recover BGE's wholesale power supply costs

• option contracts, which convey the right to buy or sell a and include an administrative fee. The administrative fee commodity, financial instrument, or index at a includes a shareholder return component and an incremental predetermined price.

cost component.

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SFAS No. 133, Accounting for Derivative Instruments and Income Statement HedgingActivities, as amended, requires that we recognize at fair Risk Derivative Classification value all derivatives not qualifying for accrual accounting under Optimize mix of Interest rate swaps Interest expense the normal purchase and normal sale exception. We record fixed and derivatives that are designated as hedges in "Risk management floating-rate debt assets or liabilities" and derivatives not designated as hedges in "Mark-to-market energy assets or liabilities" in our Consolidated Value of natural Forward contracts Fuel and purchased Balance Sheets. gas in storage and price and energy expenses We record changes in the value of derivatives that are not basis swaps designated as cash-flow hedges in earnings during the period of We record changes in the fair value of interest rate swaps change. We record changes in the fair value of derivatives and the debt being hedged in "Risk management assets and designated as cash-flow hedges that are effective in offsetting the liabilities" and "Long-term debt" and changes in the fair value of variability in cash flows of forecasted transactions in other the gas being hedged and related derivatives in "Fuel stocks" and comprehensive income until the forecasted transactions occur. At "Risk management assets and liabilities" in our Consolidated the time the forecasted transactions occur, we reclassify the Balance Sheets. In addition, we record the difference between amounts recorded in other comprehensive income into earnings. interest on hedged fixed-rate debt and floating-rate swaps in We record the ineffective portion of changes in the fair value of "Interest expense" in the periods that the swaps settle.

derivatives used as cash-flow hedges immediately in earnings.

We summarize our cash-flow hedging activities under SFAS Unamortized Energy Assets and Liabilities No. 133 and the income statement classification of amounts Unamortized energy contract assets and liabilities represent the reclassified from "Accumulated other comprehensive income remaining unamortized balance of non-derivative energy (loss)" as follows: contracts that we acquired or derivatives designated as normal purchases and normal sales that we had previously recorded as Income Statement "Mark-to-market energy assets or liabilities" or "Risk Risk Derivative Classification management assets and liabilities." The initial amount recorded Interest rate risk Interest rate swaps Interest expense represents the fair value of the contract at the time of associated with acquisition or designation, and the balance is amortized over the new debt life of the contract in relation to the present value of the issuances underlying cash flows. The amortization of these values is discussed in the Revenues and Fuel and PurchasedEnergy Expenses Nonregulated Futures and Nonregulated sections of this Note.

energy sales forward revenues contracts Credit Risk Nonregulated fuel Futures and Fuel and purchased Credit risk is the loss that may result from counterparty and energy forward energy expenses non-performance. We are exposed to credit risk, primarily purchases contracts through our merchant energy business. We use credit policies to manage our credit risk, including utilizing an established credit Nonregulated gas Futures and Fuel and purchased approval process, daily monitoring of counterparty limits, purchases for forward energy expenses employing credit mitigation measures such as margin, collateral resale contracts and or prepayment arrangements, and using master netting price and basis agreements. We measure credit risk as the replacement cost for swaps open energy commodity and derivative positions (both Regulated gas Price and basis Fuel and purchased mark-to-market and accrual) plus amounts owed from swaps energy expenses counterparties for settled transactions. The replacement cost of purchases for resale open positions represents unrealized gains, less any unrealized losses where we have a legally enforceable right of setoff.

We designate certain derivatives as fair value hedges. We Electric and gas utilities, cooperatives, and energy marketers record changes in the fair value of these derivatives and changes comprise the majority of counterparties underlying our assets in the fair value of the hedged assets or liabilities in earnings as from our wholesale marketing and risk management activities.

the changes occur. We summarize our fair value hedging We held cash collateral from these counterparties totaling activities and the income statement classification of changes in $388.4 million as of December 31, 2005 and $145.9 million as the fair value of these hedges and the related hedged items as of December 31, 2004. These amounts are included in follows: "Customer deposits and collateral" in our Consolidated Balance Sheets.

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Taxes BGE also pays Maryland public service company franchise We summarize our income taxes in Note 10. BGE and our other tax on distribution, and delivery of electricity and natural gas.

subsidiaries record their allocated share of our consolidated We include the franchise tax in "Taxes other than income taxes" federal income tax liability using the percentage complementary in our Consolidated Statements of Income.

method specified in U.S. income tax regulations. As you read this section, it may be helpful to refer to Note 10. Earnings Per Share Basic earnings per common share (EPS) is computed by dividing Income Tax Expense earnings applicable to common stock by the weighted-average We have two categories of income tax expense--current and number of common shares outstanding for the year. Diluted deferred. We describe each of these below: EPS reflects the potential dilution of common stock equivalent

" current income tax expense consists solely of regular tax shares that could occur if securities or other contracts to issue less applicable tax credits, and common stock were exercised or converted into common stock.

• deferred income tax expense is equal to the changes in Our dilutive common stock equivalent shares consist of the net deferred income tax liability, excluding amounts stock options and other stock-based compensation awards. The charged or credited to accumulated other comprehensive following table presents stock options that were not dilutive and income. Our deferred income tax expense is increased or were excluded from the computation of diluted EPS in each reduced for changes to the "Income taxes recoverable period, as well as the dilutive common stock equivalent shares as through future rates (net)" regulatory asset (described follows:

later in this Note) during the year.

Year Ended December 31, 2005 2004 2003 Tax Credits (In millions)

We have deferred the investment tax credits associated with our Non-dilutive stock options 0.1 - 1.2 regulated business and assets previously held by our regulated Dilutive common stock equivalent business in our Consolidated Balance Sheets. The investment tax shares 2.2 1.0 0.4 credits are amortized evenly to income over the life of each property. We reduce current income tax expense in our Stock-Based Compensation Consolidated Statements of Income for the investment tax Under our long-term incentive plans, we have granted stock credits and other tax credits associated with our nonregulated options, performance-based units, performance and service-based businesses.

restricted stock, and equity to officers, key employees, and We have certain investments in facilities that manufacture members of the Board of Directors. We discuss these awards in solid synthetic fuel produced from coal as defined under the more detail in Note 14.

Internal Revenue Code for which we claim tax credits on our As discussed in more detail in the Accounting Standards Federal income tax return. We recognize the tax benefit of these Adopted section later in this Note, we elected to early adopt credits in our Consolidated Statements of Income when we SFAS No. 123 Revised (SFAS No. 123R), Share-BasedPayment, believe it is highly probable that the credits will be sustained.

on October 1, 2005, which was prior to the required effective date of January 1, 2006. SFAS No. 123R requires companies to DeferredIncome Tax Assets and Liabilities recognize compensation expense for all equity-based We must report some of our revenues and expenses differently compensation awards issued to employees that are expected to for our financial statements than for income tax return -purposes. vest. Equity-based compensation awards include stock options, The tax effects of the temporary differences in these items are restricted stock, and any other share-based payments.

reported as deferred income tax assets or liabilities in our Under SFAS No. 123R, we recognize compensation cost Consolidated Balance Sheets. We measure the deferred income ratably or in tranches (depending if the award has cliff or graded tax assets and liabilities using income tax rates that are currently vesting) over the period during which an employee is required to in effect. provide service in exchange for the award, which is typically a A portion of our total deferred income tax liability relates one to five-year period. We use a forfeiture assumption to to our regulated business, but has not been reflected in the rates estimate the number of awards that are expected to vest during we charge our customers. We refer to this portion of the liability the service period, and ultimately true-up the estimated expense as "Income taxes recoverable through future rates (net)." We to the actual expense associated with vested awards. We estimate have recorded that portion of the net liability as a regulatory the fair value of stock option awards on the date of grant using asset in our Consolidated Balance Sheets. We discuss this further the Black-Scholes option-pricing model and we re-measure the in Note 6.

fair value of liability awards each reporting period.

State and Local Taxes State and local income taxes are included in "Income taxes" in our Consolidated Statements of Income.

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The following table presents the pro-forma effect on net Cash and Cash Equivalents income and earnings per share for all outstanding stock options All highly liquid investments with original maturities of three and stock awards in each period that the fair value provisions of months or less are considered cash equivalents.

SFAS No. 123R were not in effect. We do not capitalize any portion of our stock-based compensation. Accounts Receivable and Allowance for Uncollectibles Accounts receivable are stated at the historical carrying amount Year Ended December 31, 2005 2004 2003 net of write-offs and allowance for uncollectibles. We establish (In millions, except an allowance for uncollectibles based on our expected exposure per share amounts) to the credit risk of customers based on a variety of factors.

Net income, as reported $623.1 $539.7 $277.3 Add: Actual stock-based Materials, Supplies, and Fuel Stocks compensation expense We record our fuel stocks, emissions credits, coal held for resale, determined under intrinsic and materials and supplies at the lower of cost or market. We value method and included in determine cost using the average cost method for all of our reported net income, net of inventory other than our coal held for resale for which we use related tax effects 17.8* 13.2 12.0 the specific identification method.

Deduct: Pro-forma stock-based compensation expense determined under fair value Financial Investments based method for all awards, In Note 4, we summarize the financial investments that are in net of related tax effects (24.5)* (21.3) (20.7) our Consolidated Balance Sheets.

SFAS No. 115, Accountingfor Certain Investments in Debt Pro-forma net income $616.4 $531.6 $268.6 and Equity Securities, applies particular requirements to some of Earnings per share: our investments in debt and equity securities. We report those Basic-as reported $ 3.51 $ 3.14 $ 1.67 investments at fair value, and we use either specific identification Basic-pro-forma $ 3.47 $ 3.09 $ 1.62 or average cost to determine their cost for computing realized Diluted-as reported $ 3.47 $ 3.12 $ 1.66 Diluted-pro-forma $ 3A3 $ 3.07 $ 1.61 gains or losses.

• Represents expense for the nine months ended September 30, 2005, which was prior to adoption of SFAS No. 123R Available-for-Sale Securities We classify our investments in the nuclear decommissioning In the table above, the stock-based compensation expense trust funds as available-for-sale securities. We describe the included in reported net income under the intrinsic value nuclear decommissioning trusts and the related asset retirement method is as follows:

obligations later in this Note. In addition, we have investments Year Ended December 31, 2005* 2004 2003 in U.S. Treasury securities and trust assets securing certain executive benefits that are classified as available-for-sale securities.

(In millions)

We include any unrealized gains or losses on our Stock options $ 0.3 $ 1.0 $ 1.8 available-for-sale securities in "Accumulated other comprehensive Restricted stock 23.2 17.0 16.4 5.1 2.9 income in our Consolidated Statements of Common Performance-based units -

Equity grants 0.4 0.5 0.4 Shareholders' Equity and Comprehensive Income and Consolidated Statements of Capitalization.

Total stock-based compensation expense (pre-tax) $29.0 $21.4 $18.6 Evaluation of Assets for Impairment and Other Than Total stock-based compensation Temporary Decline In Value expense (after-tax) $17.8 $13.2 $12.0 Long-Lived Assets

• Represents expense for the nine months ended September 30, We are required to evaluate certain assets that have long lives 2005, which was prior to adoption ofSFAS No. 123R (for example, generating property and equipment and real estate) to determine if they are impaired when certain conditions exist.

During the fourth quarter of 2005, we recognized SFAS No. 144, Accountingfor the Impairment or Disposal of

$12.8 million after-tax, or $21.1 million pre-tax of stock-based Long-Lived Assets, provides the accounting requirements for compensation expense under the fair value method in accordance impairments of long-lived assets and proved gas properties. We with SFAS No. 123R. This was comprised of $14.1 million for are required to test our long-lived assets for recoverability stock options, $5.0 million for restricted stock, $1.9 million for whenever events or changes in circumstances indicate that their performance-based units, and $0.1 million for equity grants. We carrying amount may not be recoverable.

discuss our stock-based compensation plans in more detail in We determine if long-lived assets and proved gas properties Note 14.

are impaired by comparing their undiscounted expected future cash flows to their carrying amount in our accounting records.

We would record an impairment loss if the undiscounted 88

expected future cash flows from an asset were less than the assets with finite lives. We discuss the changes in our intangible carrying amount of the asset. Proven gas properties' cash flows assets in more detail in Note 5.

are determined at the field level. Undiscounted expected future cash flows include risk-adjusted probable and possible reserves. Property, Plant and Equipment, Depreciation, Depletion, We are also required to evaluate our equity-method and Amortization, and Accretion of Asset Retirement cost-method investments (for example, in partnerships that own Obligations power projects) for impairment. APB No. 18, The Equity Method We report our property, plant and equipment at its original cost, ofAccountingfor Investments in Common Stock (APB No. 18), unless impaired under the provisions of SFAS No. 144.

provides the accounting requirements for these investments. The Our original costs include:

standard for determining whether an impairment must be " material and labor, recorded under APB No. 18 is whether the investment has " contractor costs, and experienced a loss in value that is considered an "other than a " construction overhead costs, financing costs, and costs temporary" decline in value. for asset retirement obligations (where applicable).

We are also required to evaluate unproved property at least We own an undivided interest in the Keystone and annually to determine if it is impaired under SFAS No. 19, Conemaugh electric generating plants in Western Pennsylvania, FinancialAccounting and Reporting by Oil and Gas Producing as well as in the transmission line that transports the plants' Properties.Impairment for unproved property occurs if there are output to the joint owners' service territories. Our ownership no firm plans to continue drilling, lease expiration is at risk, or interests in these plants are 20.99% in Keystone and 10.56% in historical experience necessitates a valuation allowance. Conemaugh. These ownership interests represented a net We use our best estimates in making these evaluations and investment of $171.8 million at December 31, 2005 and consider various factors, including forward price curves for $190.9 million at December 31, 2004. Each owner is energy, fuel costs, legislative initiatives, and operating costs. responsible for financing its proportionate share of the plants' However, actual future market prices and project costs could working funds. Working funds are used for operating expenses vary from those used in our impairment evaluations, and the and capital expenditures. Operating expenses related to these impact of such variations could be material. plants are included in "Operating expenses" in our Consolidated Statements of Income. Capital costs related to these plants are Debt and Equity Securities included in "Nonregulated property, plant and equipment" in Our investments in debt and equity securities, which primarily our Consolidated Balance Sheets.

consist of our nuclear decommissioning trust fund investments, The "Nonregulated property, plant and equipment" in our are subject to impairment evaluations under FASB Staff Position Consolidated Balance Sheets includes nonregulated generation (FSP) 115-1, The Meaning of Other-Than-Temporary Impairment construction work in progress of $228.8 million at and Its Application to Certain Investments. FSP 115-1 requires us December 31, 2005 and $206.4 million at December 31, 2004.

to determine whether a decline in fair value of an investment When we retire or dispose of property, plant and below the amortized cost basis is other than temporary. If we equipment, we remove the asset's cost from our Consolidated determine that the decline in fair value is judged to be other Balance Sheets. We charge this cost to accumulated depredation than temporary, the cost basis of the investment must be written for assets that were depreciated under the group, straight-line down to fair value as a new cost basis. method. This includes regulated propertyý plant and equipment and nonregulated generating assets transferred from BGE to our Intangible Assets merchant energy business. For all other assets, we remove the Goodwill is the excess of the purchase price of an acquired accumulated depreciation and amortization amounts from our Consolidated Balance Sheets and record any gain or loss in our business over the fair value of the net assets acquired. We account for goodwill and other intangibles under the provisions Consolidated Statements of Income.

of SFAS No. 142, Goodwill and Other IntangibleAssets. We do The costs of maintenance and certain replacements are not amortize goodwill and certain other intangible assets. SFAS charged to "Operating expenses" in our Consolidated Statements No. 142 requires us to evaluate goodwill and other intangibles of Income as incurred.

for impairment at least annually or more frequently if events and Our oil and gas exploration and production activities circumstances indicate the business might be impaired. Goodwill consist of working interests in gas producing fields located in Texas, Louisiana, Oklahoma, and Alabama. We account for these is impaired if the carrying value of the business exceeds fair value. Annually, we estimate the fair value of the businesses we activities under the successful efforts method of accounting.

have acquired using techniques similar to those used to estimate Acquisition, development, and exploration costs are capitalized as future cash flows for long-lived assets as previously discussed. If permitted by SFAS No.19, FinancialAccounting and Reporting by the estimated fair value of the business is less than its carrying Oil and Gas Producing Companies. Costs of drilling exploratory value, an impairment loss is required to be recognized to the wells are initially capitalized and later charged to expense if extent that the carrying value of goodwill is greater than its fair reserves are not discovered or deemed not to be commercially viable. Other exploratory costs are charged to expense when value. SFAS No. 142 also requires the amortization of intangible incurred.

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Capitalized exploratory well costs were $11.4 million at Accretion Expense December 31, 2005 and $7.2 million at December 31, 2004, In the first quarter of 2003, we adopted SFAS No. 143, and do not include amounts that were capitalized and Accountingfor Asset Retirement Obligations,which provides the subsequently expensed within the same period. During 2005, accounting requirements for recognizing an estimated liability there were $1.4 million of well costs capitalized at for legal obligations associated with the retirement of tangible December 31, 2004 that were reclassified to well, facilities, and long-lived assets, and recognized a $112.1 million pre-tax, or equipment based on the determination of proved reserves. $67.7 million after-tax, gain as a cumulative effect of change in No exploratory well costs have been capitalized for a accounting principle.

period greater than one year since the completion of drilling. At December 31, 2005, $883.5 million of our total asset retirement obligation of $908.0 was associated with the Depreciationand Depletion Expense decommissioning of our nuclear power plants-Calvert Cliffs We compute depreciation for our generating, electric Nuclear Power Plant (Calvert Cliffs), Nine Mile Point Nuclear transmission and distribution, and gas distribution facilities. We Station (Nine Mile Point) and Ginna. We have also recorded compute depletion for our exploration and production asset retirement obligations associated with our other generating activities. Depreciation and depletion are determined using the facilities and certain other long-lived assets. We record a following methods: liability when we are able to reasonably estimate the fair value

" the group straight-line method, approved by the of any future legal obligations associated with retirement that Maryland PSC, applied to the average investment, have been incurred and capitalize a corresponding amount as adjusted for anticipated costs of removal less salvage, in part of the book value of the related long-lived assets. The classes of depreciable property based on an average rate increase in the capitalized cost is included in determining of approximately 3.5% per year for our regulated depreciation expense over the estimated useful life of these business, assets. Since the fair value of the asset retirement obligations is

" the group straight-line method using rates averaging determined using a present value approach, accretion of the approximately 2.5% per year for the fossil generating liability due to the passage of time is recognized each period to assets transferred from BGE to our merchant energy "Accretion of asset retirement obligations" in our Consolidated business and our nuclear generating assets, Statements of Income until the settlement of the liability. We

" the modified units of production method (greater of record a gain or loss when the liability is settled after straight-line method or units of production method) retirement.

for fossil generating assets constructed after The change in our 'Asset retirement obligations" liability deregulation that were not previously owned by BGE, during 2005 was as follows:

or

" the units-of-production method over the remaining life (In millions) of the estimated proved reserves at the field level for Liability at January 1, 2005 $825.0 acquisition costs and over the remaining life of proved Liabilities incurred 19.1 developed reserves at the field level for development Liabilities settled costs. The estimates for gas reserves are based on Accretion expense 62.1 internal calculations. Revisions to cash flows 1.8 Other assets are depreciated primarily using the Liability at December 31, 2005 $908.0 straight-line method and the following estimated useful lives:

"Liabilities incurred" in the table above primarily reflect Asset Estimated Useful Lives asset retirement obligations recorded in connection with the adoption of the FASB issued Interpretation No. (FIN) 47, Building and improvements 5 - 50 years Accountingfor ConditionalAsset Retirement Obligations--an Office equipment and furniture 3 - 20 years Interpretationof FASB Statement No. 143, as well as those Transportation equipment 5 - 15 years incurred in connection with our investments in gas producing Computer software 3 - 10 years fields. FIN 47 is discussed in more detail later in this Note.

We discuss the investments in gas producing fields in more Amortization Expense detail in Note 15.

Amortization is an accounting process of reducing an amount in our Consolidated Balance Sheets over a period of time that Nuclear Fuel approximates the useful life of the related item. When we We amortize the cost of nuclear fuel, including the quarterly reduce amounts in our Consolidated Balance Sheets, we fees we pay to the Department of Energy for the future increase amortization expense in our Consolidated Statements disposal of spent nuclear fuel, based on the energy produced of Income. over the life of the fuel. These fees are based on the kilowatt-hours of electricity sold. We report the amortization expense for nuclear fuel in "Fuel and purchased energy expenses" in our Consolidated Statements of Income.

90

Nuclear Decommissioning As the owner of Calvert Cliffs, we are required, along Effective January 1, 2003, we began to record decommissioning with other domestic utilities, by the Energy Policy Act of 1992 expense for Calvert Cliffs in accordance with SFAS No. 143. to make contributions to a fund for decommissioning and The "Asset retirement obligations" liability associated with the decontaminating the Department of Energy's uranium decommissioning of Calvert Cliffs was $308.2 million at enrichment facilities. The contributions are paid by BGE and December 31, 2005 and $286.1 million at December 31, generally payable over 15 years with escalation for inflation and 2004. Our contributions to the nuclear decommissioning trust are based upon the proportionate amount of uranium enriched funds for Calvert Cliffs were $17.6 million for 2005, by the Department of Energy for each utility. BGE will make

$22.0 million for 2004 and $13.2 million for 2003. Under the the last payment in 2006. BGE amortizes the deferred costs of Maryland PSC's order deregulating electric generation, BGE's decommissioning and decontaminating the Department of customers must pay a total of $520 million in 1993 dollars, Energy's uranium enrichment facilities. The previous owners adjusted for inflation, to decommission Calvert Cliffs. BGE is retained the obligation for Nine Mile Point and Ginna.

collecting this amount on behalf of and passing it to Calvert Cliffs Nuclear Power Plant, Inc. Calvert Cliffs Nuclear Power Capitalized Interest and Allowance for Funds Used Plant, Inc. is responsible for any difference between this During Construction CapitalizedInterest amount and the actual costs to decommission the plant.

We began to record decommissioning expense for Nine Our nonregulated businesses capitalize interest costs under Mile Point in accordance with SFAS No. 143 on January 1, SFAS No. 34, CapitalizingInterest Costs, for costs incurred to 2003. The 'Asset retirement obligations" liability associated finance our power plant construction projects, real estate with the decommissioning was $378.7 million at December 31, developed for internal use, and other capital projects.

2005 and $351.5 million at December 31, 2004. We determined that the decommissioning trust funds established Allowance for Funtd Used During Construction (AFC) for Nine Mile Point are adequately funded to cover the future BGE finances its construction projects with borrowed funds costs to decommission the plant and as such, no contributions and equity funds. BGE is allowed by the Maryland PSC to were made to the trust funds during the years ended record the costs of these funds as part of the cost of December 31, 2005, 2004, and 2003. construction projects in its Consolidated Balance Sheets. BGE Upon the closing of the Ginna acquisition in 2004, the does this through the AFC, which it calculates using rates seller transferred $200.8 million in decommissioning funds. In authorized by the Maryland PSC. BGE bills its customers for return, we assumed all liability for the costs to decommission the AFC plus a return after the utility property is placed in the unit. We believe that this transfer will be sufficient to cover service.

the future costs to decommission the plant and as such, no The AFC rates are 9.4% for electric plant, 8.6% for gas contributions were made to the trust funds during the years plant, and 9.2% for common plant. BGE compounds AFC ended December 31, 2005 and 2004. Effective June 2004, we annually. Effective December 2005, the gas plant AFC rate was began to record decommissioning expense for Ginna in reduced to 8.5%.

accordance with SFAS No. 143. The "Asset retirement obligations" liability associated with the decommissioning was Long-Term Debt

$196.6 million at December 31, 2005 and $184.2 million at We defer all costs related to the issuance of long-term debt.

December 31, 2004. We discuss the acquisition of Ginna in These costs include underwriters' commissions, discounts or more detail in Note 15. premiums, other costs such as legal, accounting, and regulatory In accordance with Nuclear Regulatory Commission fees, and printing costs. We amortize these costs into interest (NRC) regulations, we maintain external decommissioning expense over the life of the debt.

trusts to fund the costs expected to be incurred to When BGE incurs gains or losses on debt that it retires decommission Calvert Cliffs, Nine Mile Point, and Ginna. The prior to maturity, it amortizes those gains or losses over the NRC requires utilities to provide financial assurance that they remaining original life of the debt.

will accumulate sufficient funds to pay for the cost of nuclear decommissioning. The assets in the trusts are reported in Accounting Standards Issued "Nuclear decommissioning trust funds" in our Consolidated FSP 115-1 and 124-1 Balance Sheets. These amounts are legally restricted for funding In November 2005, FASB Staff Position SFAS 115-1 and the costs of decommissioning. We classify the investments in SFAS 124-1 (FSP 115-I and 124-I), The Meaning of Other-Than-TemporaryImpairment and its Application to Certain the nuclear decommissioning trust funds as available-for-sale Investments, was issued to replace the measurement and securities, and we report these investments at fair value in our Consolidated Balance Sheets as previously discussed in this recognition criteria of EITF 03-1. FSP 115-1 and 124-1 Note. Investments by nuclear decommissioning trust funds are references existing guidance in SFAS No. 115, Accountingfor guided by the "prudent man" investment principle. The funds CertainInvestments in Debt and Equity Securities, SEC Staff are prohibited from investing directly in Constellation Energy Accounting Bulletin No. 59, Accountingfor Noncurrent or its affiliates and any other entity owning a nuclear power Marketable Equity Securities, and APB No. 18. FSP 115-1 and plant. 124-1 requires an other-than-temporary analysis to be 91

completed each reporting period (i.e., every quarter) beginning As Reported Pro-Forma after December 15, 2005. We do not expect the adoption of Including Excluding Year Ended SFAS No. 123R SFAS No. 123R this standard to have a material impact on our, or BGE's, December 31, 2005 Adoption Adoption Impact financial results.

(In millions, except share data)

Income before income Accounting Standards Adopted taxes $810.8 $824.9 $ (14.1)

SFAS No. 123 Revised Income from In December 2004, the FASB issued SFAS No. 123R, which continuing operations 606.7 615.2 (8.5) revises SFAS No. 123, Accounting for Stock-Based Compensation, Net income 623.1 631.6 (8.5) and supersedes APB No. 25, Accountingfor Stock Issued to Net cash provided by operating activities 672.5 706.4 (33.9)

Employees. We previously disclosed in our 2004 Annual Report Net cash provided by on Form 10-K that we planned to adopt SFAS No. 123R financing activities 351.1 317.2 33.9 effective July 1, 2005. The Securities and Exchange Earnings per share-Commission issued Final Rule 74 in April 2005, which delayed basic 3.51 3.56 (0.05)

Earnings per share-the required implementation of SFAS No. 123R until diluted 3.47 3.51 (0.04)

January 1, 2006. The adoption of SFAS No. 123R did not have a material We elected to early adopt SFAS No. 123R on October 1, impact on BGE's financial results. We discuss our stock-based 2005, using the Modified Prospective Application method compensation programs in more detail in Note 14.

without restatement of prior periods. Under this method, we began to amortize compensation cost for the remaining portion SFAS No. 153 of our outstanding awards for which the requisite service was In December 2004, the FASB issued SFAS No. 153, Exchanges not yet rendered at October 1, 2005. Compensation cost for of Nonmonetary Assets, an amendment ofAPB Opinion No. 29.

these awards will be based on the fair value of those awards as SFAS No. 153 amends APB Opinion No. 29 to require disclosed on a pro-forma basis in the Stock-Based Compensation nonmonetary exchanges to be measured at the fair value of the section of this Note. We will determine the fair value of and exchanged assets unless the transaction does not have account for awards that are granted, modified, or settled after commercial substance. SFAS No. 153 was effective for October 1, 2005 in accordance with SFAS No. 123R.

nonmonetary exchanges occurring after June 30, 2005. The We do not expect the impact of this standard on our adoption of this standard did not have a material impact on ongoing operating results will be materially different than the results as previously disclosed on a pro-forma basis in the Stock- our, or BGE's, financial results.

Based Compensation section of this Note. Our share-based FIN 47 awards will continue to be accounted for substantially as they were prior to the implementation of SFAS No. 123R, other In March 2005, the FASB issued FIN 47, Accountingfor ConditionalAsset Retirement Obligations--anInterpretation of than the requirement for expensing stock options. We recognized a small, favorable cumulative effect of change in FASB Statement No. 143. FIN 47 was effective December 31, 2005. FIN 47 clarifies that asset retirement obligations that are accounting principle of $0.2 million after-tax due to the conditional upon a future event are subject to the provisions of requirement to reduce compensation expense for estimated forfeitures relating to outstanding unvested service-based SIAS No. 143. Under SFAS No. 143, we are required to restricted stock awards and performance-based unit awards at recognize an estimated liability for legal obligations associated with the retirement of tangible long-lived assets. Our October 1, 2005.

conditional asset retirement obligations relate primarily to The following table presents the impact of adoption of SFAS No. 123R on income from continuing operations, asbestos removal at certain of our generating facilities. We income before income taxes, net income, cash flow from recorded an asset retirement obligation for these facilities of

$13.9 million and recorded a $7.4 million after-tax charge to operating and financing activities, and basic and diluted earnings as a cumulative effect of change in accounting earnings per share:

principle. The adoption of FIN 47 did not have a material impact on BGE's financial results.

92

2Other Events 2005 Events Discontinued Operations Oleander Pre-Tax After-Tax In March 2005, we reached an agreement in principle to sell our (In millions) Oleander generating facility, a four-unit peaking plant located in Merger-related transaction costs $(17.0) $(15.6) Florida. Our merchant energy business classified Oleander as Workforce reduction costs (4.4) (2.6) held for sale and performed an impairment test under SFAS Income from discontinued operations No. 144 as of March 31, 2005. The impairment test indicated International investments 40.1 20.6 that the carrying value of the plant was higher than its fair value Oleander 4.9 3.0 less costs to sell, and therefore in March 2005 we recorded an impairment charge of $4.8 million pre-tax as part of Total income from discontinued discontinued operations.

operations 45.0 23.6 In June 2005, we completed the sale of this facility for Total other items $ 23.6 $ 5.4 $217.6 million, and recognized a pre-tax gain on the sale of

$1.2 million as part of discontinued operations.

Merger-Related Transaction Costs International Investments We incurred external costs associated with the execution of our In October 2005, we sold Constellation Power International merger agreement with FPL Group. We discuss the pending Investments, Ltd. (CPII). CPII held our other nonregulated merger in more detail in Note 15.

international investments, which represented an interest in a Panamanian electric distribution company and an investment in Workforce Reduction Costs a fund that holds interests in two South American energy As a result of the workforce reduction efforts initiated in 2004, projects. We received cash of $71.8 million and recognized a in 2005 we were required to record a pre-tax settlement charge pre-tax gain of approximately $25.6 million, or $16.1 million in our Consolidated Statements of Income of $4.4 million for after-tax. An additional $3.6 million of the sales price is one of our qualified pension plans under SFAS No. 88, contingent upon the collection of certain receivables by Employers'Accountingfor Settlements and Curtailments ofDefined March 31, 2006. At December 31, 2005, we recognized Benefit Pension Plans andfor Termi"'ation Benefits. This charge approximately $2.2 million of this amount based on cash reflects recognition of the portion of deferred actuarial gains and collections, which is included in the $25.6 million pre-tax gain.

losses associated with employees who were terminated as part of We expect to recognize the remaining $1.4 million of contingent the restructuring or retired in 2005 and who elected to receive proceeds in 2006 once realization is assured beyond a reasonable their pension benefit in the form of a lump-sum payment. In doubt.

accordance with SFAS No. 88, a settlement charge must be Presented in the table below are the amounts related to recognized when lump-sum payments exceed annual pension these discontinued operations that are included in "Income (loss) plan service and interest cost.

from discontinued operations" in our Consolidated Statements In 2005, we completed the 2004 workforce reduction of Income.

effort. As a result, no involuntary severance liability was recorded at December 31, 2005.

Oleander International Investments Total Year Ended December 31, 2005 2004 2003 2005 2004 2003 2005 2004 2003 (In millions)

Revenues $14.7 $42.5 $45.4 $228.1 $219.7 $214.5 $242.8 $262.2 $259.9 Income before income taxes 8.5 20.5 20.2 14.5 16.8 17.7 23.0 37.3 37.9 Net income 5.3 12.6 11.9 4.5 9.4 7.1 9.8 22.0 19.0 Pre-tax impairment charge (4.8) - - - - - (4.8) - -

After-tax impairment charge (3.0) - - - - - (3.0) - -

Pre-tax gain on sale 1.2 - - 25.6 - - 26.8 After-tax gain on sale 0.7 - - 16.1 - - 16.8 Income from discontinued operations, net of taxes 3.0 12.6 11.9 20.6 9.4 7.1 23.6 22.0 19.0 We recognizeda pre-tax lossfrom discontinuedoperations of $(75.6) million, before income taxes of $(26.5) millionfrom the sale of our Hawaiian Geothermalfacility in 2004. We discuss the sale of this facility later in this Note.

93

2004 Events In March 2004, after reviewing final binding offers, Pre-Tax After-Tax management committed to a plan to sell the facility that met (In millions) the "held for sale" criteria under SFAS No. 144. Under SFAS Workforce reduction costs $ (9.7) $ (5.9) No. 144, we record assets and liabilities held for sale at the Recognition of 2003 synthetic fuel tax lesser of the carrying amount or fair value less cost to sell.

credits - 35.9 The fair value of the facility as of March 31, 2004, based (Loss) income from discontinued on the bids under consideration, was below carrying value.

operations Therefore, we recorded a $71.6 million pre-tax, or Hawaiian geothermal facility (75.6) (49.1)

International investments

$47.3 million after-tax, impairment charge during the first 16.8 9.4 Oleander 20.5 12.6 quarter of 2004. We reported the after-tax impairment charge as a component of "Loss from discontinued operations" in our Total loss from discontinued operations (38.3) (27.1) Consolidated Statements of Income. Additionally, we recognized $1.5 million pre-tax, or $1.0 million after-tax, of Total other items $(48.0) $ 2.9 earnings from the facility for the quarter ended March 31,

'Loss (income) from discontinued operations"reflects the 2004 as a component of "Loss from discontinued operations."

reclassification of earningsfrom our Oleander and international In June 2004, we completed the sale of the facility. Based operations due to their sale in 2005. on the final sales price and other costs incurred over the remainder of the year, we recognized an additional loss of Workforce Reduction Costs $5.5 million pre-tax, or $2.8 million after-tax. The sale of this In the fourth quarter of 2004, we approved a restructuring of facility was reflected in our merchant energy business reportable the work forces of the Nine Mile Point and Calvert Cliffs segment. In addition, as a result of a current audit relating to nuclear generating stations that was effective in January 2005. prior tax years for this facility, we could record additional gain In connection with this restructuring, approximately 108 or loss from discontinued operations in future periods.

employees received severance and other benefits under our We have not reclassified the prior year results of existing benefit programs. At December 31, 2004, we accrued operations, which were reported under the equity method as the estimated total cost of this reduction in workforce of "Nonregulated revenues," based on the immateriality of the

$9.7 million pre-tax, or $5.9 million after-tax, in accordance amounts involved. The facility had a $4.0 million net loss, with applicable accounting requirements. including a $1.1 million cumulative effect of change in accounting principle for the adoption of SFAS No. 143, during Synthetic Fuel Tax Credits 2003.

In 2003, we purchased 99% ownership in a South Carolina facility that produces synthetic fuel. We did not recognize in 2003 Events our Consolidated Statements of Income the tax benefit of

$35.9 million for credits claimed on our South Carolina facility Pre-Tax After-Tax in 2003 pending receipt of a favorable private letter ruling (In millions) from the Internal Revenue Service (IRS). In April 2004, we Workforce reduction costs $ (2.1) $ (1.3) received a favorable private letter ruling. We believe receipt of Income from discontinued operations the private letter ruling provides assurance that it is highly International Investments 17.7 7.1 probable that the credits will be sustained. Therefore, we Oleander 20.2 11.9 recognized the tax benefit of $35.9 million in our Consolidated Total income from discontinued Statements of Income in 2004. We discuss the synthetic fuel operations 37.9 19.0 tax credits in more detail in Note 10.

Total other items $35.8 $17.7 Loss from Discontinued Operations "Incomefrom discontinued operations*reflects the reclassificationof In the fourth quarter of 2003, we began to re-evaluate our earningsfrom our Oleander and internationaloperations due to strategy regarding our geothermal generating facility in Hawaii.

theirsale in 2005.

The reevaluation of our strategy included soliciting bids to determine the level of interest in the facility. As of December 31, 2003, management determined that disposal of the facility was more likely than not to occur. As a result, we evaluated the facility for impairment as of December 31, 2003, in accordance with SFAS No. 144, Accountingfor the Impairment or DisposalofLong-Lived Assets, and determined that the facility was not impaired primarily due to indicative bids from third parties above the carrying value of the assets.

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Workfo ret Reduction Costs HurricaneIsabel During 2003, we recorded $2.1 million in pre-tax expense, or In September 2003, Hurricane Isabel caused damage to the

$1.3 million after-tax, of which BGE recorded $0.7 million electric and gas distribution system of BGE. As a result, BGE pre-tax, associated with deferred payments to employees eligible incurred capitalized costs of $32.0 million and maintenance for the 2001 Voluntary Special Early Retirement Program. expenses of $36.8 million, or $22.2 million after-tax to restore its distribution system. The maintenance expenses included

$32.1 million pre-tax, or $19.4 million after-tax, of incremental expenses.

31Information by Operating Segment Our reportable operating segments are--Merchant Energy, " Our regulated electric business purchases, transmits, Regulated Electric, and Regulated Gas: distributes, and sells electricity in Central Maryland.

• Our merchant energy business is nonregulated and " Our regulated gas business purchases, transports, and includes: sells natural gas in Central Maryland.

- full requirements load-serving sales of energy and Our remaining nonregulated businesses:

capacity to utilities and commercial, industrial, " design, construct, and operate heating, cooling, and and governmental customers, cogeneration facilities for commercial, industrial, and

- structured transactions and risk management municipal customers throughout North America, and services for various customers (including hedging

• provide home improvements, service electric and gas of output from generating facilities and fuel costs appliances, service heating, air conditioning, plumbing, and trading activities managed through daily electrical, and indoor air quality systems, and provide value at risk and stop loss limits and liquidity natural gas marketing to residential customers in Central guidelines), Maryland.

- gas retail energy products and services to In addition, we own several investments that we do not commercial, industrial, and governmental consider to be core operations. These include financial customers, investments and real estate projects. During 2005, we sold our

- fossil, nuclear, and interests in hydroelectric other nonregulated international investments. We discuss this generating facilities and qualifying facilities, fuel sale in more detail in Note 2.

processing facilities, and power projects in the Our Merchant Energy, Regulated Electric, and Regulated United States, Gas reportable segments are strategic businesses based principally

- products and services to upstream (exploration upon regulations, products, and services that require different and production) and downstream (transportation technology and marketing strategies. We evaluate the and storage) wholesale natural gas customers, performance of these segments based on net income. We

- coal sourcing services for the variable or fixed account for intersegment revenues using market prices. We supply needs of North American and present a summary of information by operating segment on the international power generators, and next page.

- generation operations and maintenance services.

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Reportable Segments Merchant Regulated Regulated Other Energy Electric Gas Nonregulated Business Business Business Businesses Eliminations Consolidated (In millions) 2005 Unaffiliated revenues $13,926.8 $2,036.5 $ 961.7 $207.0 $ - $17,132.0 Intersegment revenues 859.3 - 11.1 - (870.4) -

Total revenues 14,786.1 2,036.5 972.8 207.0 (870.4) 17,132.0 Depreciation, depletion, and amortization 269.6 185.8 46.6 40.2 - 542.2 Fixed charges 177.9 80.3 26.4 10.0 15.5 310.1 Income tax expense 81.9 101.2 21.2 (0.2) - 204.1 Income on discontinued operations 3.0 - - 20.6 - 23.6 Cumulative effects of changes in accounting principles (7.4) - - 0.2 -- (7.2)

Net income (a) 425.8 149.4 26.7 21.2 -623.1 Segment assets 16,620.4 3,424A 1,222.5 476.1 (269.5) 21,473.9 Capital expenditures 708.9 240.7 50.6 31.8 - 1,032.0 2004 Unaffiliated revenues $ 9,362.9 $1,967.6 $ 755.0 $200.9 $ - $ 12,286.4 Intersegment revenues 984.6 0.1 2.0 0.2 (986.9) -

Total revenues 10,347.5 1,967.7 757.0 201.1 (986.9) 12,286.4 Depreciation and amortization 239.2 194.2 48.1 24.2 - 505.7 Fixed charges 196.2 80.3 29.1 15.4 5.8 326.8 Income tax expense 61.3 86.8 15.9 (7.1) - 156.9 (Loss) income on discontinued operations (36.5) - - 9.4 - (27.1)

Net income (loss) (b) 389.9 131.1 22.2 (3.5) - 539.7 Segment assets 12,395.6 3,402.2 1,163.4 675.7 (289.8) 17,347.1 Capital expenditures 455.0 209.0 56.0 42.0 - 762.0 2003 Unaffiliated revenues $ 6,420.5 $1,921.5 $ 712.7 $399.4 $ - $ 9,454.1 Intersegment revenues 1,167.0 0.1 13.3 0.2 (1,180.6) -

Total revenues 7,587.5 1,921.6 726.0 399.6 (1,180.6) 9,454.1 Depreciation and amortization 214.6 181.7 46.6 11.0 - 453.9 Fixed charges 191.9 96.8 28.2 17.3 2.3 336.5 Income tax expense 138.6 73.5 32.0 6.5 - 250.6 Income on discontinued operations 11.9 - - 7.1 - 19.0 Cumulative effects of changes in accounting principles (198.4) - - -- (198.4)

Net income (c) 114.6 107.5 43.0 12.2 - 277.3 Segment assets 10,503.7 3,512.0 1,069.1 778.7 (270.5) 15,593.0 Capital expenditures 419.0 236.0 53.0 53.0 -761.0 Certainprior-yearamounts have been reclassified to conform with the current years presentation.

(a) Our merchant energy business, our regulatedelectric business, our regulatedgas business, and our other nonregulatedbusinesses recognized after-tax charges of $13.0 million, $3.7 million, $1.3 million, and $0.2 million for merger-relatedtransactioncosts and workforce reduction costs as described in more detail in Note 2.

(b) Our merchant energy business recognized after-tax income of $30.0 million, for recognition of 2003 syntheticfuel tar credits and workforce reduction costs as described in more detail in Note 2.

(c) Our merchant energy business, our regulated electric business, our regulatedgas business, and our other nonregulatedbusinesses recognized after-tax charges of $0.7 million, $0.4 million, $0.1 million, and $0.1 million, respectively, for workforce reduction costs as described in more detail in Note 2.

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4Investments Investments In Qualifying Facilities and Power Projects Investments Classified as Available-for-Sale Our merchant energy business holds up to a 50% voting interest We classify the following investments as available-for-sale:

in 24 operating domestic energy projects that consist of electric " nuclear decommissioning trust funds, generation, fuel processing, or fuel handling facilities. Of these

• investments in treasury securities, and 24 projects, 17 are "qualifying facilities" that receive certain " trust assets securing certain executive benefits.

exemptions and pricing under the Public Utility Regulatory This means we do not expect to hold them to maturity, Policy Act of 1978 based on the facilities' energy source or the and we do not consider them trading securities.

use of a cogeneration process. We show the fair values, gross unrealized gains and losses, Investments in qualifying facilities and domestic power and amortized cost basis for all of our available-for-sale projects held by our merchant energy business consist of the securities, in the following tables. We use specific identification following: to determine cost in computing realized gains and losses.

Amortized Unrealized Unrealized Fair At December 31, 2005 2004 At December 31, 2005 Cost Basis Gains Losses Value (In millions) (In millions)

Coal $127.8 $128.7 Marketable equity Hydroelectric 55.9 55.8 securities $ 804.4 $112.7 $(3.8) $ 913.3 Geothermal 43.7 46.3 Corporate debt and Biomass 48.0 50.2 U.S. treasuries 114.8 0.2 (1.4) 113.6 Fuel Processing 23.8 22.5 State municipal bonds 107.1 2.8 (0.8) 109.1 Solar 7.0 10.4 Totals $1,026.3 $115.7 $(6.0) $1,136.0 Total $306.2 $313.9 Amortized Unrealized Unrealized Investments in qualifying facilities and domestic power At December 31, 2004 Cost Basis Gains Losses Fair Value projects were accounted for under the following methods:

(In millions)

At December 31, 2005 2004 Marketable equity securities $786.1 $72.5 $ (2.5) $ 856.1 (In millions) Corporate debt and Equity method $299.2 $303.5 U.S. treasuries 73.7 0.7 (0.2) 74.2 Cost method 7.0 10.4 State municipal bonds 94.3 2.9 (0.2) 97.0 Total power projects $306.2 $313.9 Totals $954.1 $76.1 $ (2.9) $1,027.3 Our percentage voting interest in qualifying facilities and In addition to the above securities, the nuclear domestic power projects accounted for under the equity method decommissioning trust funds included $12.2 million at ranges from 16% to 50%. Equity in earnings of these power December 31, 2005 and $30.6 million at December 31, 2004 of projects was $3.6 million in 2005, $18.0 million in 2004, and cash and cash equivalents.

$2.1 million in 2003. The preceding tables include $110.3 million in 2005 of net Our power projects include investments of $228.6 million unrealized gains and $73.3 million in 2004 of net unrealized in 2005 and $240.2 million in 2004 that sell electricity in gains associated with the nuclear decommissioning trust funds California under power purchase agreements. Our other that are reflected as a change in the nuclear decommissioning nonregulated businesses also held international energy projects trust funds in our Consolidated Balance Sheets.

accounted for under the equity method of $4.5 million at We have unrealized losses relating to certain December 31, 2004. In 2005, we sold our interests in the available-for-sale investments included in our decommissioning international energy projects. We discuss this sale in more detail trust funds. We believe these losses are temporary in nature and in Note 2. expect the investments to recover their value in the future given the long-term nature of these investments. Decommissioning will not occur until the operating licenses for our nuclear facilities expire. We show the fair values and unrealized losses of our investments that were in a loss position at December 31, 2005 and 2004 in the tables on the next page.

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At December 31, 2005 The corporate debt securities, U.S. Government agency Less than 12 months or obligations, and state municipal bonds mature on the following 12 months more Total schedule:

Description of Fair Unrealized Fair Unrealized Fair Unrealized Securities Value Losses Value Losses Value Losses At December 31, 2005 (In millions) (In millions)

Marketable equity Less than 1 year $ 0.9 securities $ 22.3 $(2.9) $ 2.3 $(0.3) $ 24.6 $(3.2) 1-5 years 58.0 Corporate debt 5-10 years 95.3 and U.S. More than 10 years 68.5 treasuries 71.8 (1.1) 11.8 (0.3) 83.6 (1.4)

Total maturities of debt securities $ 222.7 State municipal bonds 46.0 (0.6) 11.8 (0.2) 57.8 (0.8)

Total temporarily Investments in Variable Interest Entities impaired We have a significant interest in the following variable interest securities $140.1 $(4.6) $25.9 $(0.8) $166.0 $(5.4) entities (VIE) for which we are not the primary beneficiary:

Nature of Date of At December 31, 2004 VIE Involvement Involvement Less than 12 months or 12 months more Total Power projects and Equity investment and Prior to 2003 Description of Fair Unrealized Fair Unrealized Fair Unrealized fuel supply entities guarantees Securities Value Losses Value Losses Value Losses Power contract Power sale agreements, March 2005 (In millions) monetization loans, and Marketable equity entities guarantees securities $ 23.6 $(2.4) $ - $ - $ 23.6 $(2.4)

We discuss the nature of our involvement with the power Corporate debt and U.S. contract monetization VIEs in the Customer Contract treasuries 15.3 (0.1) 10.1 (0.1) 25.4 (0.2) Restructuringsection on the next page.

State municipal The following is summary information available as of bonds 18.7 (0.2) 3.3 - 22.0 (0.2) December 31, 2005 about the VIEs in which we have a Total temporarily significant interest, but are not the primary beneficiary:

impaired securities $ 57.6 $(2.7) $13.4 $(0.1) $ 71.0 $(2.8)

Power Gross and net realized gains and losses on available-for-sale Contract All securities were as follows: Monetization Other VIEs VIEs Total 2005 2004 2003 (In millions)

(In millions) Total assets $898.2 $226.0 $1,124.2 Gross realized gains $12.3 $ 4.1 $ 6.7 Total liabilities 650.7 76.1 726.8 Gross realized losses (9.3) (7.7) (6.1) Our ownership interest - 46.0 46.0 Other ownership interests 247.5 103.9 351.4 Net realized (losses) gains $ 3.0 $(3.6) $ 0.6 Our maximum exposure Gross realized losses for 2004 include a $4.5 million pre-tax to loss 75.8 67.8 143.6 impairment charge we recognized on a nuclear decommissioning The maximum exposure to loss represents the loss that we trust fund investment that we believed represented an other than would incur in the unlikely event that our interests in all of temporary decline in value. these entities were to become worthless and we were required to fund the full amount of all guarantees associated with these entities. Our maximum exposure to loss as of December 31, 2005 consists of the following:

" outstanding loans and letters of credit totaling

$85.2 million,

• the carrying amount of our investment totaling

$45.7 million, and

• debt and performance guarantees totaling $12.7 million.

We assess the risk of a loss equal to our maximum exposure to be remote.

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Customer ContractRestructuring We recorded the closing of this transaction in our In March 2005, our merchant energy business closed a financial statements as follows:

transaction in which we assumed from a counterparty two power sales contracts with existing VIEs. Under the contracts, Balance Sheet Cash Flows we sell power to the VIEs which, in turn, sell that power to an Fair value of power Risk management Financing cash electric distribution utility through 2013. sales contracts liabilities inflow The VIEs previously were created by the counterparty to assumed issue debt in order to monetize the value of the original (designated as contracts to purchase and sell power. The difference between cash-flow hedge) the contract prices at which the VIEs purchase and sell power Settlement of Mark-to-market and Operating cash is used to service the debt of the VIEs, which totaled existing derivative risk management outflow

$619 million at December 31, 2005. liabilities liabilities The market price for power at the closing of our Third-party loan Other assets Investing cash outflow transaction was higher than the contract price under the existing power sales contracts we assumed. Therefore, we We recorded the gross compensation we received to received compensation totaling $308.5 million, equal to the net assume the power sales contracts as a financing cash inflow present value of the difference between the contract price under because it constitutes a prepayment for a portion of the market the power sales contracts and the market price of power at price of power, which we will sell to the VIEs over the term of closing. We used a portion of this amount to settle the contracts and does not represent a cash inflow from current

$68.5 million of existing derivative liabilities with the same period operating activities. We record the ongoing cash flows counterparty, and we also loaned $82.8 million to the holder related to the sale of power to the VIEs as a financing cash of the equity in the VIEs. As a result, we received net cash at inflow in accordance with SFAS No. 149, Amendment ofFASB dosing of $157.2 million. We also guaranteed our subsidiaries' Statement No. 133 on Derivative and Hedging Activities.

performance under the power sales contracts. If the electric distribution utility were to default under its The table below summarizes the transaction and the net obligation to buy power from the VIEs, the equity holder cash received at dosing: could transfer its equity interests to us in lieu of repaying the loan. In this event, we would have the right to seek recovery of (In millions) our losses from the electric distribution utility.

Gross compensation from original power sales contracts counterparty equal to fair value of power sales contracts at closing $308.5 Settlement of existing derivative liabilities (68.5)

Tfhird-party loan secured by equity in VIE (82.8)

Net cash received at closing $157.2 99

5 Intangible Assets Goodwill The following is our, and BGE's, estimated amortization Goodwill is the cost of an acquisition less the fair value of the expense for 2006 through 2010 for the intangible assets included net assets acquired. Our goodwill balance is primarily related to in our, and BGE's, Consolidated Balance Sheets at our merchant energy business acquisitions that occurred in 2002 December 31, 2005:

and 2003. The changes in the carrying amount of goodwill for the years ended December 31, 2005 and 2004 are as follows: Year Ended December 31. 2006 2007 2008 2009 2010 (In millions)

Balance at Goodwill Balance at Estimated amortization expense-2005 January 1, Acquired Other December 31, Nonregulated businesses $30.9 $29.2 $23.9 $21.5 $18.8 (In millions) Estimated amortization expense-Goodwill $144.8 $2.3 $ - $147.1 BGE 17.7 15.3 12.6 9.9 9.5 Total estimated amortization Balance at Goodwill Balance at expense-Constellation Energy $48.6 $44.5 $36.5 $31.4 $28.3 2004 January 1. Acquired Other(a) December 31, (In millions) Unamortized Energy Contracts Goodwill $146.3 $- $(1.5) $144.8 As discussed in Note 1. unamortized energy contract assets and (a) Other represents purchase price adjustments liabilities represent the remaining unamortized balance of nonderivative energy contracts acquired or derivatives designated Goodwill is not amortized; rather, it is evaluated for as normal purchases and normal sales, which we previously impairment at least annually. We evaluated our goodwill in 2005 recorded as mark-to-market energy or risk management assets and 2004 and determined that it was not impaired. For tax and liabilities.

purposes, $118.0 million of our goodwill balance is deductible.

During 2005, we acquired several pre-existing nonderivative contracts that had been originated by other parties in prior Intangible Assets Subject to Amortization periods when market prices were lower than current levels, for Intangible assets with finite lives are subject to amortization over which we received approximately $530 million in cash and other their estimated useful lives. The primary assets included in this consideration and recorded a liability in "Unamortized energy category are as follows:

contracts." In addition, during 2005, we designated as normal At December 31, 2005 2004 purchases and normal sales contracts that we had previously Accumul- Accumul- recorded as cash-flow hedges in "Risk management liabilities."

Gross ated Gross ated Carrying Amortiz- Net Carrying Amortiz- Net This resulted in a reclassification of $888.5 million from "Risk Amount ation Asset Amount ation Asset management liabilities" to "Unamortized energy contract (In millions) liabilities."

Software $364.7 $156.5 $208.2 $388.4 $205.4 $183.0 We present separately in our Consolidated Balance Sheets Permits and the net unamortized energy contract assets and liabilities for licenses 49.4 12.6 36.8 37.7 5.7 32.0 Operating these contracts. The table below presents the gross and net manuals and carrying amount and accumulated amortization of the net procedures 38.6 6.0 32.6 38.6 4.5 34.1 liability that we have recorded in our Consolidated Balance Other 29.7 14.3 15.4 20.0 12.1 7.9 Sheets:

Total $482.4 $189.4 $293.0 $484.7 $227.7 $257.0 At Dcember 31. 2005 2004 BGE had intangibleassets with a gross carryingamount of $181.4 million Acoumul- Accumul-and accumulatedamortization of $98.7 million in 2005 and a gross carrying ated ated Carrying Amortiz- Net Carrying Arnortiz- Net amount of $253.1 million and accumulatedamortization of $161.2 million Amount ation liability Amount ation liability in 2004 and are included in the table above. Substantiallyall ofBGE's intangibleassets relate to sofiware. (InMillions)

Unamortized energy We recognized amortization expense related to our contracts, net $(1,449.2) $ (37.8) $(1,411.4) $(4.9) $31.2 $(36.1) intangible assets as follows:

The table below presents the estimated net impact on our Year Ended December 31, 2005 2004 2003 operating results for the amortization for these assets and (In millions) liabilities over the next five-years:

Nonregulated businesses $56.9 $114.2 $ 84.6 Year Ended December 31, 2006 2007 2008 2009 2010 BGE 26.3 41.4 33.0 (in milons)

Total Constellation Energy $83.2 $155.6 $117.6 Estimated amortization $(433.7) $(310.4) $(226.5) $(153.3) $(145.4) 100

6Regulatory Assets (net)

As discussed in Note 1, the Maryland PSC and the FERC Net Cost of Removal provide the final determination of the rates we charge our As discussed in Note 1, we use the group depreciation method customers for our regulated businesses. Generally, we use the for the regulated business. This method is currently an same accounting policies and practices used by nonregulated acceptable method of accounting under accounting principles companies for financial reporting under accounting principles generally accepted in the United States of America and is widely generally accepted in the United States of America. However, used in the energy, transportation, and telecommunication sometimes the Maryland PSC or FERC orders an accounting industries.

treatment different from that used by nonregulated companies to Historically, under the group depreciation method, the determine the rates we charge our customers. When this anticipated costs of removing assets upon retirement were happens, we must defer certain regulated expenses and income provided for over the life of those assets as a component of in our Consolidated Balance Sheets as regulatory assets and depreciation expense. However, effective January 1, 2003, we liabilities. We then record them in our Consolidated Statements adopted SFAS No. 143, Accounting for Asset Retirement of Income (using amortization) when we include them in the Obligations. In addition to providing the accounting rates we charge our customers. requirements for recognizing an estimated liability for legal We summarize regulatory assets and liabilities in the obligations associated with the retirement of tangible long-lived following table, and we discuss each of them separately below. assets, SFAS No. 143 precludes the recognition of expected net future costs of removal as a component of depreciation expense At December 31, 2005 2004 or accumulated depreciation.

(In millions) BGE is required by the Maryland PSC to use the group Electric generation-related regulatory asset $173.6 $ 192.4 depreciation method, including cost of removal, under regulatory Net cost of removal (148.7) (132.5) accounting. In accordance with SIAS No. 71, BGE continues to Income taxes recoverable through future rates accrue for the future cost of removal for its regulated gas and (net) 70.9 74.9 electric assets by increasing its regulatory liability. This liability is Deferred postretirement and postemployment

. benefit costs 22.6 25.8 relieved when actual removal costs are incurred.

Deferred environmental costs 14.9 17.6 Deferred fuel costs (net) 16.2 4.3 Income Taxes Recoverable Through Future Rates (net)

Workforce reduction costs 7.3 14.1 As described in Note 1, income taxes recoverable through future Other (net) (2.5) (1.2) rates are the portion of our net deferred income tax liability that Total regulatory assets (net) $154.3 $ 195.4 is applicable to our regulated business, but has not been reflected in the rates we charge our customers. These income taxes Certainprior-yearamounts have been reclassifiedto conform with represent the tax effect of temporary differences in depreciation the current year's presentation.

and the allowance for equity funds used during construction, offset by differences in deferred tax rates and deferred taxes on Electric Generation-Related Regulatory Asset deferred investment tax credits. 'We amortize these amounts as As a result of the deregulation of electric generation, BGE does not meet the requirements for the application of SFAS No. 71 the temporary differences reverse.

for the electric generation portion of its business. In accordance Deferred Postretirement and Postemployment Benefit with SFAS No. 101, Regulated Enterprises-Accountingfor the Costs DiscontinuationofApplication of FASB Statement No. 71, and Deferred postretirement and postemployment benefit costs are EITF 97-4, Deregulation of the Pricing ofElectricity-Issues the costs we recorded under SFAS No. 106, Employers' Related to the Application ofFASB Statements No. 71 and 101, all Accountingfor Postretirement Benefits Other Than Pensions, and individual generation-related regulatory assets and liabilities must SFAS No. 112, Employers'Accountingfor Postemployment Benefits, be eliminated from our balance sheet unless these regulatory in excess of the costs we included in the rates we charge our assets and liabilities will be recovered in the regulated portion of customers. We began amortizing these costs over a 15-year the business. BGE wrote-off all of its individual, generation-period in 1998.

related regulatory assets and liabilities. BGE established a single, new generation-related regulatory asset for amounts to be collected through its regulated transmission and distribution business. The new regulatory asset is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules.

101

Deferred Environmental Costs We exclude deferred fuel costs from rate base because their Deferred environmental costs are the estimated costs of existence is relatively short-lived. These costs are recovered in the investigating and cleaning up contaminated sites we own. We following year through our fuel rates.

discuss this further in Note 12. We amortized $21.6 million of these costs (the amount we had incurred through October 1995) Workforce Reduction Costs and are amortizing $6.4 million of these costs (the amount we The portions of the costs associated with our VSERP and incurred from November 1995 through June 2000) over 10-year workforce reduction programs that relate to BGE's gas business periods in accordance with the Maryland PSC's orders. We are deferred as regulatory assets in accordance with the Maryland applied for and received rate relief for an additional $5.4 million PSC's orders in prior rate cases. As a result of a 2005 gas rate of clean-up costs incurred during the period from July 2000 case, the remaining regulatory assets associated with workforce through November 2005. These costs will be amortized over a reductions totaling $7.3 million as of December 31, 2005 will 10-year period beginning in January 2006. be amortized over a 3-year period beginning January 2006.

These remaining regulatory assets were previously amortized over Deferred Fuel Costs 5-year periods beginning in January and February 2002.

As described in Note 1, deferred fuel costs are the difference between our actual costs of purchased energy and our fuel rate revenues collected from customers. We reduce deferred fuel costs as we collect them from or refund them to our customers.

7Pension, Postretirement, Other Postemployment, and Employee Savings Plan Benefits We offer pension, postretirement, other postemployment, and We fund the qualified plans by contributing at least the employee savings plan benefits. BGE employees participate in minimum amount required under IRS regulations. We calculate the benefit plans that we offer. We describe each of our plans the amount of funding using an actuarial method called the separately below. Nine Mile Point offers its own pension, projected unit credit cost method. The assets in all of the plans postretirement, other postemployment, and employee savings at December 31, 2005 and 2004 were mostly marketable equity plan benefits to its employees. The benefits for Nine Mile Point and fixed income securities.

are included in the tables beginning on the next page.

We use a December 31 measurement date for our pension, Postretirement Benefits postretirement, other postemployment, and employee savings We sponsor defined benefit postretirement health care and life plans. insurance plans that cover the vast majority of our employees.

Generally, we calculate the benefits under these plans based on Pension Benefits age, years of service, and pension benefit levels or final base pay.

We sponsor several defined benefit pension plans for our We do not fund these plans.

employees. These include basic qualified plans that most For nearly all of the health care plans, retirees make employees participate in and several nonqualified plans that are contributions to cover a portion of the plan costs.

available only to certain employees. A defined benefit plan Contributions for employees who retire after June 30, 1992 specifies the amount of benefits a plan participant is to receive are calculated based on age and years of service. The amount of using information about the participant. Employees do not retiree contributions increases based on expected increases in contribute to these plans. Generally, we calculate the benefits medical costs. For the life insurance plan, retirees do not make under these plans based on age, years of service, and pay. contributions to cover a portion of the plan costs.

Sometimes we amend the plans retroactively. These Effective in 2002, we amended our postretirement medical retroactive plan amendments require us to recalculate benefits plans for all subsidiaries other than Nine Mile Point. Our related to participants' past service. We amortize the change in contributions for retiree medical coverage for future retirees that the benefit costs from these plan amendments on a straight-line were under the age of 55 on January 1, 2002 are capped at the basis over the average remaining service period of active 2002 level. We also amended our plans to increase the Medicare employees. eligible retirees' share of medical costs.

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In 2003, the President signed into law the Medicare Obligations, Assets, and Funded Status Prescription Drug Improvement and Modernization Act of 2003 In June 2004, we assumed pension and postretirement benefit (the Act). This legislation provides a prescription drug benefit obligations for new employees in connection with the acquisition for Medicare beneficiaries, a benefit that we provide to our of the R.E., Ginna Nuclear Plant (Ginna). The sellers of Ginna Medicare eligible retirees. Our actuaries previously concluded transferred assets into our qualified plan trust. We discuss the that prescription drug benefits available under our postretirement Ginna acquisition further in Note 15.

medical plan are "actuarially equivalent" to Medicare Part D and As a result of a workforce reduction initiative in the thus qualify for the subsidy under the Act. In 2005, the Center generation business, pension and postretirement special for Medicare and Medicaid Services accepted our application to termination benefits were recorded in December 2004. We receive a tax reimbursement for eligible prescription drug costs. discuss the workforce reduction initiative further in Note 2.

The expected subsidy will offset a portion of our share of the We show the change in the benefit obligations, plan assets, cost of the underlying postretirement prescription drug coverage. and funded status of the pension and postretirement benefit This legislation reduced our Accumulated Postretirement Benefit plans in the following tables.

Obligation by $42.6 million at January 1, 2005 and our annual postretirement benefit expense in 2005 by $5.4 million. This Pension Postretirement subsidy is expected to reduce our estimated 2006 cash per capita Benefits Benefits 2005 2004 2005 2004 medical costs from $3,289 to $2,694, or by 18%.

(In millions)

Additional Minimum Pension Liability Adjustment Change in benefit obligation Our pension accumulated benefit obligation has exceeded the Benefit obligation at January 1 $1,513.2 $1,326.0 $423.2 $430.8 fair value of our plan assets since 2001. At December 31, 2005 Service cost 44.8 40.1 7.6 6.5 and 2004, our pension obligations were greater than the fair Interest cost 83.9 82.4 23.8 22.6 value of our plan assets for our qualified and our nonqualified Plan participants' pension plans as follows: contributions - - 7.4 5.8 Actuarial loss (gain) 143.6 117.1 35.6 (17.2)

Qualified Plans Non-Qualified Ginna acquisition - 40.5 - 6.1 At December 31, 2005 Nine Mile Other Plans Total Special termination benefits (0.4) 2.4 - 1.2 (In millions) Benefits paid (1) (106.5) (95.3) (37.2) (32.6)

Accumulated benefit Benefit obligation at obligation $127.1 $1,325.1 $56.3 $1,508.5 December 31 $1,678.6 $1,513.2 $460.4 $423.2 Fair value of assets 84.9 1,022.2 - 1,107.1 (1) Benefits paid include annuitypayments, lump-sum distributions,and Unfunded obligation $ 42.2 $ 302.9 $56.3 $ 401.4 transer/sto nonqualifieddeerredcompensationplans.

Qualified Plans Non-Qualified Pension Postretirement At December 31, 2004 Nine Mile Other Plans Total Benefits Benefits (In millions) 2005 2004 2005 2004 Accumulated benefit (In millions) obligation $122.1 $1,185.9 $46.1 $1,354.1 Change in plan assets Fair value of assets 78.6 1,005.8 - 1,084.4 Fair value of plan assets at Unfunded obligation $ 43.5 $ 180.1 $46.1 $ 269.7 January I $1,084A $ 954.6 $ - $ -

Actual return on plan assets 76.2 114.1 - -

As required under SFAS No. 87, Employers'Accountingfor Employer contribution 53.0 60.2 29.8 26.7 Pensions, we recorded additional minimum pension liability Plan participants' contributions - - 7.4 5.9 adjustments as follows:

Ginna acquisition - 50.8 - -

Benefits paid (1) (106.5) (95.3) (37.2) (32.6)

Increase (Decrease)

Pension PAccumulated ComprehensiveOther Fair value of plan assecs at Loss Liability Intangiblec December 31 $1,107.1 $1,084.4 $ - $

Adjustment Asset

• Pre-tax After-tax (1) Benefits paid include annuity payments, lump-sum distributions,and (In millions) transfers to nonquaified deferredcompensation plans.

Cumulative through 2003 $295.2 $46.7 $(248.5) $(150.2) 2004 64.4 (6.1) (70.5) (42.6) 2005 121.4 (6.1) (127.5) (77.1)

Total $481.0 $34.5 $(446.5) $(269.9)

• Included in 'Other assets in our ConsolidatedBalance Sheets.

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Pension Postrctiremcnt Expected Cash Benefit Payments Benefits Benefits The pension and postretirement benefits we expect to pay in At December 3L 2005 2004 2005 2004 each of the next five calendar years and in the aggregate for the (In millions) subsequent five years are shown below. These estimated benefits Funded Status are based on the same assumptions used to measure the benefit Funded Status $ (571.5) $ (428.8) $(460.4) $(423.2)

Unrecognized net actuarial loss 618.9 480.8 150.8 121.1 obligation at December 31, 2005, but includes benefits Unrecognized prior service cost 32.2 37.9 (33.2) (36.7) attributable to estimated future employee service.

Unrecognized transition obligation - - 14.9 17.0 Postretirement Benefits Pension liability adjustment (481.0) (359.6) - -

Accrued benefit cost $ (401.4) $ (269.7) $(327.9) $(321.8) Before After Pension Medicare Medicare Benefits* Part D Subsidy Part D Net Periodic Benefit Cost (In millions)

We show the components of net periodic pension benefit cost in 2006 $ 95.8 $ 27.4 $(2.7) $ 24.7 the following table: 2007 90.3 30.4 (2.6) 27.8 2008 92.7 31.5 (2.8) 28.7 Year Ended December 31, 2005 2004 2003 2009 96.6 32.4 (2.9) 29.5 (In millions) 2010 101.7 33.0 (3.0) 30.0 Components of net periodic pension 2011-2015 611.1 176.1 (17.0) 159.1 benefit cost Service cost $ 44.8 $ 40.1 $ 33.7

• Evcludes transfers to nonqualifieddeferred compensation plans Interest cost 83.9 82.3 81.3 Expected return on plan assets (100.2) (97.9) (95.0) Assumptions Amortization of unrecognized prior service cost We made the assumptions below to calculate our pension and 5.7 5.8 5.8 Recognized net actuarial loss 25.1 14.3 5.0 postretirement benefit obligations and periodic cost.

Amount capitalized as construction cost (7.4) (4.5) (2.6) Pension Postretirement Assumption Net periodic pension benefit cost (1) $ 51.9 $ 40.1 $ 28.2 Benefits Benefits Impacts 2005 2004 2005 2004 Calculation of (1) Net periodic pension benefit cost excludes SFAS No. 88 settlement charge of$4.4 million in 2005. SFAS No. 88 settlement charge of $2.8 million Benefit and termination benefits of $2.4 million in 2004, and SFAS No. 88 Obligation and settlement charge of$2.8 million in 2003. BGE! portion of our net Discount rate 5.50% 5.75% 5.50% 5.75% Periodic Cost periodic pension benefit costs, excluding amount capitalizea was Expected return

$15.0 million in 2005, $8.6 million in 2004, and $4.3 million in 2003. The vast majority of our retirees are BGE employees. on plan assets 9.0 9.0 N/A N/A Periodic Cost Rate of Benefit We show the components of net periodic postretirement compensation Obligation and benefit cost in the following table: increase 4.0 4.0 4.0 4.0 Periodic Cost Our 9.0% overall expected long-term rate of return on plan Year Ended December 31, 2005 2004 2003 assets reflects our long-term investment strategy in terms of asset (In millions) mix targets and expected returns for each asset class. Our Components of net periodic postretirement benefit cost discount rate is based on Moodys Aa long-term bond index. We Service cost $ 7.6 $ 6.5 $ 6.1 periodically perform studies to ensure that this index is Interest cost 23.8 22.6 26.3 comparable to the use of a high quality bond portfolio whose Amortization of transition obligation 2.1 2.1 2.1 maturities match our expected benefit payments. Effective in Recognized net actuarial loss 6.4 3.1 5.8 Amortization of unrecognized prior 2006, we reduced our assumed expected return on pension plan service cost (3.5) (3.5) assets from 9.0% to 8.75% based on a fundamental analysis Amount capitalized as construction cost (7.7) (7.0) (8.8) utilizing expected long-term returns applied to our targeted asset Net periodic postredirement benefit cost (1) $ 28.7 $23.8 $28.0 allocation.

(1) Net periodicpostretirement benefit cost excluda SFAS No. 106 termination benefits of $1.2 million in 2004. BGE! portion ofour net periodicpostretirement beneft cost, excluding amounts capitalieze was

$17.4 millon in 2005, $15.1 million in 2004, and $19.4 million in 2003.

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Annual health care inflation rate assumpt ions also impact Contributions and Benefit Payments the calculation of our postretirement benefit obligation and We contributed an additional $50 million to our qualified periodic cost. We assumed the following healtih care inflation pension plans in March 2005, even though there was no IRS rates to produce average claims by year as shovwn below: required minimum contribution in 2005. We expect to contribute $52 million to our pension plans in 2006, even At December 31, 2005 2004 though there is no required IRS minimum contribution for Next year 9.0% 10.0% 2006. Our non-qualified pension plans and our postretirement Following year 8.0% 9.0% benefit programs are not funded. We estimate that we will Ultimate trend rate 5.0% 5.0% incur approximately $3 million in pension benefits for our Year ultimate trend rate reached 2010 2010 non-qualified pension plans and approximately $25 million for A one-percent increase in the health care inflation rate during 2006.

from the assumed rates would increase the acci umulated postretirement benefit obligation by approxima MAou Other Postemployment Benefits

$36.4 million as of December 31, 2005 and w We provide the following postemployment benefits:

combined service and interest costs of the post retirement

• health and life insurance benefits to eligible employees benefit cost by approximately $2.4 million ann ually. determined to be disabled under our Disability A one-percent decrease in the health care inflation rate Insurance Plan, from the assumed rates would decrease the acciumulated ltely

• income replacement payments for Nine Mile Point postretirement benefit obligation by approxima oely union-represented employees determined to be

$30.1 million as of December 31, 2005 and would decrease disabled, and the combined service and interest costs of the postretirement

• income replacement payments for other employees benefit cost by approximately $1.9 million ann ually. determined to be disabled before November 1995 (payments for employees determined to be disabled Qualified Pension Plan Assets after that date are paid by an insurance company, and The asset allocations for our qualified pension plans were as the cost is paid by employees).

follows:

The liability for these benefits totaled $54.7 million as of December 31, 2005 and $53.5 million as of December 31, At December 31, 2005 2004 2004.

Equity securities 59% 57% We assumed the discount rate for other postemployment Debt securities 32 33 benefits to be 5.25% in 2005 and 5.0% in 2004. This Other 9 10 assumption impacts the calculation of our other Total 100% 100% postemployment benefit obligation and periodic cost.

The category "Other" primarily represents investments in Employee Savings Plan Benefits financial limited partnerships. Our long-term pension plan We sponsor defined contribution savings plans that are offered investment strategy is to seek an asset mix of 53% equity, 35% to all eligible employees. The savings plans are qualified 401(k) fixed income, and 12% other investments. We rebalance our plans under the Internal Revenue Code. In a defined portfolio periodically when the sum of equity and other contribution plan, the benefits a participant is to receive result investments differs from 65% by three percentage points or from regular contributions to a participant account. Matching more, we change an outside investment advisor, or we make contributions to participant accounts are made under these contributions to the trust. plans. Matching contributions to these plans were:

We determine expected return on plan assets using a * $18.6 million; of which BGE contributed market-related value of plan assets that recognizes asset gains $5.1 million, in 2005, and losses ratably over a five-year period. * $16.7 million, of which BGE contributed

$4.7 million, in 2004, and

• $14.1 million, of which BGE contributed

$4.6 million, in 2003.

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8 Credit Facilities and Short-Term Borrowings Our short-term borrowings may include bank loans, commercial These facilities can issue letters of credit up to paper, and bank lines of credit. Short-term borrowings mature approximately $3.6 billion. Letters of credit issued under all of within one year from the date of issuance. We pay commitment our facilities totaled $2.5 billion at December 31, 2005 and fees to banks for providing us lines of credit. When we borrow $809.9 million at December 31, 2004. The increase in letters of under the lines of credit, we pay market interest rates. credit issued is primarily due to changes in collateral requirements with counterparties as a result of higher Constellation Energy commodity prices and the growth of our merchant energy Constellation Energy had committed bank lines of credit under business. Constellation Energy had no commercial paper four credit facilities of $3.6 billion at December 31, 2005 for outstanding at December 31, 2005 and 2004.

short-term financial needs as follows:

• $200.0 million 364-day bilateral credit facility expiring Merchant Energy Business in December 2006, In 2005, our merchant energy business executed several

• $1.5 billion five-year revolving credit facility expiring in short-term repurchase agreements that resulted in $0.7 million of March 2010, net short-term borrowings which matured in January 2006.

• $1.1 billion five-year revolving credit facility expiring in November 2010, and DGE

• $750.0 million five-year revolving credit facility expiring BGE had no commercial paper outstanding at December 31, in November 2010. 2005 or 2004.

We enter into these facilities to ensure adequate liquidity to BGE continues to maintain $200.0 million in committed support our operations. Currently, we use the facilities to issue 364-day bilateral credit agreements, expiring May 2006 through letters of credit primarily for our merchant energy business. November 2006. BGE can borrow directly from the banks or Additionally, we can borrow directly from the banks or use the use the agreements to allow the issuance of commercial paper.

facilities to allow the issuance of commercial paper with the exception of the $200 million bilateral facility, which only Other Nonregulated Businesses supports letters of credit. We had $290.0 million of commercial Our other nonregulated businesses had no short-term borrowings paper outstanding at February 28, 2006. outstanding at December 31, 2005 or 2004.

9 Long-Term Debt and Preference Stock Long-term Debt the buyers. We discuss the sale of this facility in more detail in Long-term debt matures in one year or more from the date of Note 2.

issuance. We detail our long-term debt in our Consolidated Statements of Capitalization. As you read this section, it may BGE be helpful to refer to those statements. BGE! FirstRefunding Mortgage Bonds BGE's first refunding mortgage bonds are secured by a Constellation Energy mortgage lien on all of its assets. The generating assets BGE During 2004, we decided to continue our ownership in a transferred to subsidiaries of Constellation Energy also remain synthetic fuel processing facility in South Carolina. We discuss subject to the lien of BGE's mortgage, along with the stock of this facility in more detail in Note 10. In connection with our Safe Harbor Water Power Corporation and Constellation decision to continue with our ownership in this facility, we are Enterprises, Inc.

committed to making fixed payments until the end of 2007. BGE is required to make an annual sinking fund payment Accordingly, during 2004, we recorded a liability of each August I to the mortgage trustee. The amount of the

$39.3 million, net of discount related to imputed interest, in payment is equal to 1% of the highest principal amount of "Long-term debt" in our Consolidated Balance Sheets for these bonds outstanding during the preceding 12 months. The fixed payments. We used an imputed interest rate because there trustee uses these funds to retire bonds from any series through was no stated interest rate on these fixed payments. The repurchases or calls for early redemption. However, the trustee imputed interest rate was calculated to be 3.47% and was cannot call the following bonds for early redemption:

based on our borrowing rate for a similar loan. " 7ýA% Series, due 2007 In connection with the sale of our international " 65A% Series, due 2008 investments, we transferred $96.3 million of long-term debt to 106

In July 2005, BGE announced a partial call of debentures at any time on or after November 21, 2008 or at

$1.9 million principal amount of its Remarketed Floating Rate any time when certain tax or other events occur.

Series Bonds due September 1, 2006 in connection with its BGE Trust II will use the interest paid on the 6.20%

annual sinking fund. The redemption was made pursuant to debentures to make distributions on the Trust Preferred the sinking fund provisions of BGE's mortgage. Bonds called Securities. The 6.20% debentures are the only assets of BGE were randomly selected by lot. Bonds called for the sinking Trust II.

fund were redeemed in part on August 26, 2005 at the sinking BGE fully and unconditionally guarantees the Trust fund call price of 100% of principal amount, plus accrued Preferred Securities based on its various obligations relating to interest from June 1, 2005 to, but not including, August 26, the trust agreement, indentures, 6.20% debentures, and the 2005. preferred security guarantee agreement.

For the payment of dividends and in the event of BGE! Other Long-Term Debt liquidation of BGE, the 6.20% debentures are ranked prior to On July 1, 2000, BGE transferred $278.0 million of preference stock and common stock.

tax-exempt debt to our merchant energy business related to the transferred assets. At December 31, 2005, BGE remains Revolving Credit Agreement contingently liable for the $269.8 million outstanding balance On December 18, 2001, one of our subsidiaries, District of this debt. Chilled Water Partnership (ComfortLink) entered into a We show the weighted-average interest rates and maturity $25.0 million loan agreement with the Maryland Energy dates for BGE's fixed-rate medium-term notes outstanding at Financing Administration (MEFA). The terms of the loan December 31, 2005 in the following table. exactly match the terms of variable rate, tax exempt bonds due December 1, 2031 issued by MEFA for ComfortLink to Weighted-Average finance the cost of building a chilled water distribution system.

Series Interest Rate The interest rate on this debt resets weekly. These bonds, and B 8.63% 2006 the corresponding loan, can be redeemed at any time at par D 6.70 2006 plus accrued interest while under variable rates. The bonds can E 6.66 2006-2012 also be converted to a fixed rate at ComfortLink's option.

G 6.08 2008 Some of the medium-term notes include a "put option." Debt Compliance and Covenants These put options allow the holders to sell their notes back to The credit facilities of Constellation Energy and BGE discussed BGE on the put option dates at a price equal to 100% of the in Note 8 have limited material adverse change clauses that principal amount. The following is a summary of only consider a material change in financial condition and are medium-term notes with put options. not directly affected by decreases in credit ratings. If these clauses are invoked, the lending institutions can decline to Series E Notes Principal Put Option Dates make new advances or issue new letters of credit, but cannot (In millions) accelerate existing amounts outstanding. The long-term debt indentures of Constellation Energy and BGE do not contain 6.75%. due 2012 $59.5 June 2007 material adverse change clauses or financial covenants.

6.75%, due 2012 25.0 June 2007 6.73%, due 2012 Certain credit facilities of Constellation Energy contain a 25.0 June 2007 provision requiring Constellation Energy to maintain a ratio of debt to capitalization equal to or less than 65%. At BGE DeferrableInterest SubordinatedDebentures December 31,' 2005, the debt to capitalization ratio as defined On November 21, 2003, BGE Capital Trust II (BGE Trust II),

in the credit agreements was 59%.

a Delaware statutory trust established by BGE, issued Certain credit agreements of BGE contain provisions 10,000,000 Trust Preferred Securities for $250 million ($25 requiring BGE to maintain a ratio of debt to capitalization liquidation amount per preferred security) with a distribution equal to or less than 65%. At December 31, 2005, the debt to rate of 6.20%.

capitalization ratio for BGE as defined in these credit BGE Trust II used the net proceeds from the issuance of agreements was 45%. At December 31, 2005, no amounts common securities to BGE and the Trust Preferred Securities were outstanding under these agreements.

to purchase a series of 6.20% Deferrable Interest Subordinated Failure by Constellation Energy, or BGE, to comply with Debentures due October 15, 2043 (6.20% debentures) from these covenants could result in the acceleration of the maturity BGE in the aggregate principal amount of $257.7 million with of the debt outstanding under these facilities. The credit the same terms as the Trust Preferred Securities. BGE Trust II facilities of Constellation Energy contain usual and customary must redeem the Trust Preferred Securities at $25 per preferred cross-default provisions that apply to defaults on debt by security plus accrued but unpaid distributions when the 6.20%

Constellation Energy and certain subsidiaries over a specified debentures are paid at maturity or upon any earlier threshold. Certain BGE credit facilities also contain usual and redemption. BGE has the option to redeem the 6.20%

customary cross-default provisions that apply to defaults on 107

debt by BGE over a specified threshold. The indentures Weighted-Average Interest Rates for Variable Rate Debt pursuant to which BGE has issued and outstanding mortgage Our weighted-average interest rates for variable rate debt were:

bonds and subordinated debentures provide that a default under any debt instrument issued under the relevant indenture At December 31, 2005 2004 may cause a default of all debt outstanding under such NonregulatedBusinesses indenture. (including Constellation Energy)

Constellation Energy also provides credit support to Loans under credit agreements 4.71% 3.58%

Calvert Cliffs, Ginna, and Nine Mile Point to ensure these Tax-exempt debt transferred from BGE 2.77% 1.54%

plants have funds to meet expenses and obligations to safely BGE operate and maintain the plants. Remarketed floating rate series mortgage bonds 3.14% 1.39%

Maturities of Long-Term Debt As discussed in Note 13 we have entered into interest rate Our long-term borrowings mature on the following schedule swaps relating to $450 million of our fixed-rate debt.

(includes sinking fund requirements):

Constellation Nonregulated Preference Stock Year Energy Businesses BGE Each series of BGE preference stock has no voting power, (In millons) except for the following:

2006 $ - $ 21.7 $ 444.6

• the preference stock has one vote per share on any 2007 600.0 21.3 122.0 charter amendment which would create or authorize 2008 - 6.1 294.8 any shares of stock ranking prior to or on a parity 2009 500.0 1A 11.5 with the preference stock as to either dividends or 2010 -

Thereafter 1,949.1 307.0 589.1 distribution of assets, or which would substantially adversely affect the contract rights, as expressly set Total long-term debt at December 31, 2005 $3,049.1 $357.5 $1,462.0 forth in BGE's charter, of the preference stock, each of which requires the affirmative vote of two-thirds of all At December 31, 2005, we had long-term loans totaling the shares of preference stock outstanding; and

$282.3 million that mature after 2005, which contain certain " whenever BGE fails to pay full dividends on the put options under which lenders could potentially require us to preference stock and such failure continues for one repay the debt prior to maturity, or which are periodically year, the preference stock shall have one vote per share remarketed and could require repayment following any on all matters, until and unless such dividends shall unsuccessful remarketing. As a result of these provisions, at have been paid in full. Upon liquidation, the holders December 31, 2005, $25.0 million is classified as current of the preference stock of each series outstanding are portion of long-term debt at BGE. entitled to receive the par amount of their shares and an amount equal to the unpaid accrued dividends.

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10 Taxes The components of income tax expense are as follows:

Year Ended December 31, 2005 2004 2003 (Dollaramounts in millions)

Income Taxes Current Federal $ 45.2 $ 22.5 $145.6 State 33.4 21.6 29.3 Current taxes charged to expense 78.6 44.1 174.9 Deferred Federal 116.6 95.8 67.6 State 16.0 24.2 15.4 Deferred taxes charged to expense 132.6 120.0 83.0 Investment tax credit adjustments (7.1) (7.2) (7.3)

Income taxes per Consolidated Statements of Income $204.1 $156.9 $250.6 Certain prioryear amounts have been reclassified to conform to the currentyear's presentation of discontinued operations.

Total income taxes are different from the amount that would be computed by applying the statutory Federal income tax rate of 35% to book income before income taxes as follows:

Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes Income from continuing operations before income taxes (excluding BGE preference stock dividends) $824.0 $736.9 $720.5 Statutory federal income tax rate 35% 35% 35%

Income taxes computed at statutory federal rate 288.4 257.9 252.2 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities 3.8 4.0 4.1 Amortization of deferred investment tax credits (7.1) (7.2) (7.3)

Synthetic fuel tax credits flowed through to income (114.9) (123.2) (35.0)

State income taxes, net of federal income tax benefit 32.8 29.3 30.9 Nondeductible merger-related transaction costs 5.3 - -

Other (4.2) (3.9) 5.7 Total income taxes $204.1 $156.9 $250.6 Effective income tax rate 24.8% 21.3% 34.8%

Certainprioryear amounts havi been reclassified to conform to the currentyears presentation of discontinuedoperations.

2004 includes credits associatedwith 2003 production at our South Carolinafacility that were recognized in the second quarter of2004 upon receipt of a favorable Private Letter Rulingfrom the IRS.

BGE's effective tax rate was 38.8% in 2005, 38.1% in 2004, and 39.2% in 2003. The difference between BGE's effective tax rate and the 35% statutory federal income tax rate is primarily related to Maryland corporate income taxes at an effective rate of 4.55%, which is net of the related federal income tax benefit.

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The major components of our net deferred income tax liability are as follows:

Constellation Energy BGE At December 31, 2005 2004 2005 2004 (In millions)

Deferred Income Taxes Deferred tax liabilities Net property, plant and equipment $1,539.3 $1,478.6 $ 526.7 $ 522.2 Qualified nuclear decommissioning trust funds 332.8 317.6 - -

Regulatory assets, net 85.5 93.0 85.5 93.0 Mark-to-market energy assets and liabilities, net 141.2 83.7 - -

Other 112.7 124.1 61.3 64.8 Total deferred tax liabilities 2,211.5 2,097.0 673.5 680.0 Deferred tax assets Asset retirement obligation 353.6 327.3 - -

Accrued pension and post-employment benefit costs 243.8 184.3 41.4 40.1 Financial investments and hedging instruments 144.7 34.5 - -

Deferred investment tax credits 24.2 26.9 5.3 5.9 Reduction of investments 7.4 23.6 - -

Other 105.6 102.1 8.3 15.7 Total deferred tax assets 879.3 698.7 55.0 61.7 Total deferred tax liability, net 1,332.2 1,398.3 618.5 618.3 Current portion of deferred tax liability, net (BGE's portion recorded in accrued expenses and other) 151.4 95.0 9.6 10.3 Long-term portion of deferred tax liability, net $1,180.8 $1,303.3 $ 608.9 $ 608.0 Certainprior-year amounts have been reclassifiedto conform with the currentyear's presentation.

Synthetic Fuel Tax Credits quarter of 2004, we received final written notice of the Our merchant energy business has investments in facilities that resolution of the examination from the IRS.

manufacture solid synthetic fuel produced from coal as defined In 2003, we purchased 99% ownership in a South under the Internal Revenue Code (IRC) for which we can Carolina facility that produces synthetic fuel. We did not claim tax credits on our Federal income tax return through recognize in our Consolidated Statements of Income the tax 2007. We recognize the tax benefit of these credits in our benefit of $35.9 million for credits claimed on our South Consolidated Statements of Income when we believe it is Carolina facility in 2003 pending receipt of a favorable private highly probable that the credits will be sustained. The synthetic letter ruling. In 2004, we received a favorable private letter fuel process involves combining coal material with a chemical ruling. We believe receipt of the private letter ruling provides reagent to create a significant chemical change. A taxpayer may reasonable assurance that it is highly probable that the credits request a private letter ruling from the IRS to support its will be sustained. Therefore, we recognized the tax benefit of position that the synthetic fuel produced undergoes a $35.9 million in our Consolidated Statements of Income significant chemical change and thus qualifies for synthetic fuel -during 2004.

tax credits. While we believe the production and sale of synthetic fuel We own a minority ownership in four synthetic fuel from all of our synthetic fuel facilities meet the conditions to facilities located in Virginia and West Virginia. These facilities qualify for tax credits under the IRC, we cannot predict the have received private letter rulings from the IRS. In timing or outcome of any future challenge by the IRS, January 2004, the IRS concluded its examination of the legislative or regulatory action, or the ultimate impact of such partnership that owns these facilities for the tax years 1998 events on the synthetic fuel tax credits that we have claimed to through 2001 and the IRS did not disallow any of the date, but the impact could be material to our financial results.

previously recognized synthetic fuel credits. During the second 110

II Leases There are two types of leases-operating and capital. Capital We recognized expense related to our operating leases as leases qualify as sales or purchases of property and are reported follows:

in our Consolidated Balance Sheets. Our capital leases are not material in amount. All other leases are operating leases and are Fuel and reported in our Consolidated Statements of Income. We expense purchased energy Operating all lease payments associated with our regulated business. Lease expenses expenses Total expense and future minimum payments for long-term, (In millions) noncancelable, operating leases are not material to BGE's 2005 $103.2 $24.8 $128.0 financial results. We present information about our operating 2004 11.0 23.1 34.1 leases below. 2003 5.1 17.6 22.7 At December 31, 2005, we owed future minimum Outgoing Lease Payments payments for long-term, noncancelable, operating leases as We, as lessee, lease some facilities and equipment. The lease follows:

agreements expire on various dates and have various renewal options. We also enter into certain power purchase agreements Power which are accounted for as operating leases. Under these Purchase agreements, we are required to make fixed capacity payments, as Year Agreements Other Total well as variable payments based on actual output of the plants. (In millions)

We record these payments as "Fuel and purchased energy 2006 $137.2 $ 22.4 $159.6 expenses" in our Consolidated Statements of Income. We 2007 135.5 17.2 152.7 exclude from our future minimum lease payments table the 2008 94.8 15.1 109.9 variable payments related to the output of the plant due to the 2009 35.3 14.1 49.4 contingency associated with these payments. 2010 31.4 13.0 44.4 Thereafter 249.3 76.2 325.5 Total future minimum lease payments $683.5 $158.0 $841.5 12 Commitments, Guarantees, and Contingencies Commitments Our merchant energy business also has committed to We have made substantial commitments in connection with our long-term service agreements and other purchase commitments merchant energy, regulated electric and gas, and other for our plants.

nonregulated businesses. These commitments relate to: Our regulated electric business enters into various long-term

" purchase of electric generating capacity and energy, contracts for the procurement of electricity. These contracts

" procurement and delivery of fuels, and expire in 2006. The cost of power under these contracts is

" long-term service agreements, capital for construction recoverable under the POLR agreement reached with the programs, and other. Maryland PSC, as discussed in Note 1, and therefore are Our merchant energy business enters into various long-term excluded from the table on the next page.

contracts for the procurement and delivery of fuels to supply our Our regulated gas business enters into various long-term generating plant requirements. In most cases, our contracts contracts for the procurement, transportation, and storage of gas.

contain provisions for price escalations, minimum purchase Our regulated gas business has gas transportation and storage levels, and other financial commitments. These contracts expire contracts that expire between 2006 and 2028. These contracts in various years between 2006 and 2017. In addition, our are recoverable under BGE's gas cost adjustment clause discussed merchant energy business enters into long-term contracts for the in Note 1, and therefore are excluded from the table on the next capacity and transmission rights for the delivery of energy to page.

meet our physical obligations to our customers. These contracts expire in various years between 2006 and 2015.

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Our other nonregulated businesses have committed to gas Guarantees purchases and to contributions of additional capital for The terms of our guarantees are as follows:

construction programs and joint ventures in which they have an interest. Expiration We have also committed to long-term service agreements 2007- 2009-2006 2008 2010 Thereafter Total and other obligations related to our information technology (In million) systems.

Competitive supply $5,514.1 $546.1 $251.6 $1,956.7 $8,268.5 At December 31, 2005, we estimate our future obligations Other 5.6 13.3 1.8 1,262.0 1,282.7 to be as follows:

Total guarantees $5,519.7 $559.4 $253.4 $3,218.7 $9,551.2 Paymcnts At December 31, 2005, Constellation Energy had a total of 2007- 2009-2006 2008 2010 Thereafter Total $9,551.2 million guarantees outstanding related to loans, credit (In miltions) facilities, and contractual performance of certain of its Merchant Energy subsidiaries as described below. These guarantees do not Purchased capacity represent our incremental obligations, and we do not expect to and energy $ 697.6 $ 891.5 $308.5 $162.7 $2,060.3 fund the full amount under these guarantees.

Fuel and transportation 2,360.3 1,054.6 436.2 575.5 4,426.6 " Constellation Energy guaranteed $8,268.5 million on Long-term service behalf of our subsidiaries for competitive supply agreements, capital, activities. These guarantees are put into place in order and other 66.3 78.9 44.6 144.8 334.6 to allow our subsidiaries the flexibility needed to Total merchant energy 3,124.2 2,025.0 789.3 883.0 6,821.5 conduct business with counterparties without having to Corporate and Other:

post other forms of collateral. While the face amount of Long-term service agreements, capital, these guarantees is $8,268.5 million, our calculated fair and other 32.0 9.7 1.9 0.6 44.2 value of obligations covered by these guarantees was Regulated: $2,830.5 million at December 31, 2005. If the parent Purchase obligations company was required to fund these subsidiary and other 42.0 49.1 - 0.2 91.3 obligations, the total amount based on December 31, Total future obligations $3,198.2 $2,083.8 $791.2 $883.8 $6,957.0 2005 market prices would be $2,830.5 million. The recorded fair value of obligations in our Consolidated Balance Sheets for guarantees was $1,333.6 million at Pending Merger with FPL Group, Inc.

December 31, 2005.

In connection with the merger agreement with FPL Group,

" Constellation Energy guaranteed $932.3 million there are certain contingencies relating to potential cash primarily on behalf of our nuclear generating facilities payments. We discuss these contingencies in Note 14 and mostly due to nuclear insurance and for credit support Note 15.

to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants.

Long-Term Power Sales Contracts

" Constellation Energy guaranteed $59.6 million on We enter into long-term power sales contracts in connection behalf of our other nonregulated businesses primarily for with our load-serving activities. We also enter into long-term loans and performance bonds of which $25.0 million power sales contracts associated with certain of our power plants.

was recorded in our Consolidated Balance Sheets at Our load-serving power sales contracts extend for terms through December 31, 2005.

2017 and provide for the sale of energy to electricity distribution

" Our merchant energy business guaranteed $19.2 million utilities and certain retail customers. Our power sales contracts for loans and other performance guarantees related to associated with our power plants extend for terms into 2014 and certain power projects in which we have an investment.

provide for the sale of all or a portion of the actual output of

" Our other nonregulated business guaranteed certain of our power plants. All long-term contracts were

$8.3 million primarily for performance bonds.

executed at pricing that approximated market rates, including " BGE guaranteed two-thirds of certain debt of Safe profit margin, at the time of execution.

Harbor Water Power Corporation, an unconsolidated investment. At December 31, 2005, Safe Harbor Water Power Corporation had outstanding debt of

$20.0 million. The maximum amount of BGE's guarantee is $13.3 million.

" BGE guaranteed the Trust Preferred Securities of

$250.0 million of BGE Trust II, an unconsolidated investment, as discussed in Note 9.

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The total fair value of the obligations for our guarantees institutional controls. In July 2004, the EPA issued a Special recorded in our Consolidated Balance Sheets at December 31, Notice/Demand Letter to BGE and three other potentially 2005 was $1,358.6 million and not the $9.6 billion of total responsible parties regarding implementation of the remedy and guarantees. We assess the risk of having to perform under these in November 2005 issued an order, expected to become effective guarantees to be minimal. in the first quarter of 2006, requiring cleanup of the site by those parties as well as 15 other parties. The total dean-up costs Environmental Matters are estimated to be approximately $10 million. We estimate our Solid and Hazardous Wute current share of site-related costs to be 11.1% of the total. In The Environmental Protection Agency (EPA) and several state December 2002, we recorded a liability in our Consolidated agencies have notified us that we are considered a potentially Balance Sheets for our share of the dean-up costs that we believe responsible party with respect to the clean-up of certain is probable. Our final share of the $10 million has not been environmentally contaminated sites. We cannot estimate the final determined and it may vary from the current estimate.

clean-up costs for all of these sites, but the current estimated costs for, and current status of, each site is described in more Spring Gardens detail below. In December 1996, BGE signed a consent order with the Maryland Department of the Environment that requires it to Metal Bank implement remedial action plans for contamination at and In 1997, the EPA, under the Comprehensive Environmental around the Spring Gardens site, located in Baltimore, Maryland.

Response, Compensation and Liability Act ("Superfund"), issued The Spring Gardens site was once used to manufacture gas from a Record of Decision (ROD) for the proposed dean-up at the coal and oil. Based on the remedial action plans, BGE estimates Metal Bank of America site, a metal reclaimer in Philadelphia. its probable clean-up costs will total $47 million. BGE has We had previously recorded a liability in our Consolidated recorded these costs as a liability in its Consolidated Balance Balance Sheets for BGE's 15.47% share of probable dean-up Sheets and has deferred these costs, net of accumulated costs. Based on current settlement negotiations among the EPA amortization and amounts it recovered from insurance and the potentially responsible parties involved at the site, we do companies, as a regulatory asset. Based on the results of studies not believe we will incur dean-up costs in excess of the amount at this site, it is reasonably possible that additional costs could recorded as a liability. The EPA and the potentially responsible exceed the amount BGE has recognized by approximately parties, induding BGE, are currently pursuing claims against $14 million. Through December 31, 2005, BGE has spent Metal Bank of America for an equitable share of expected site approximately $40 million for remediation at this site.

remediation costs. BGE also has investigated other small sites where gas was manufactured in the past. We do not expect the dean-up costs 68th Street Dump of the remaining smaller sites to have a material effect on our In 1999, the EPA proposed to add the 68th Street Dump in financial results.

Baltimore, Maryland to the Superfund National Priorities List

("NPL"), which is its list of sites targeted for clean-up and Air Quality enforcement, and sent a general notice letter to BGE and 19 In late July 2005, we received two Notices of Violation (NOVs) other parties identifying them as potentially liable parties at the from the Placer County Air Pollution Control District, Placer site. In March 2004, we and other potentially responsible parties County California (District) alleging that the Rio Bravo Rocklin formed the 68th Street Coalition, which has entered into facility located in Lincoln, California had violated certain consent order negotiations with the EPA to investigate dean-up District air emission regulations. We have a combined 50%

options for the site under the Superfund Alternative Sites ownership interest in the partnership which owns the Rio Bravo Program. While negotiations under this program are ongoing, Rocklin facility. The NOVs allege a total of 38 violations the 68th Street Dump will not be placed on the NPL. At this between January 2003 and March 2005 of either the facility's air stage, it is not possible to predict the outcome of those permit or federal, state, and county air emission standards discussions or our share of the liability. However, the costs could related to NO,, carbon monoxide, and particulate emissions, as have a material effect on our financial results. well as violations of certain monitoring and reporting requirements during that time period. The maximum civil Kane and Lombard penalties for the alleged violations range from $10,000 to The EPA issued its ROD for the Kane and Lombard Drum site $40,000 per violation. Management of the Rio Bravo Rocklin located in Baltimore, Maryland on September 30, 2003. The facility is currently evaluating the allegations in the NOVs; and ROD specifies the dean-up plan for the site, consisting of therefore, it is not possible to determine the actual liability, if enhanced reductive dechlorination, a soil management plan, and any, of the partnership that owns the Rio Bravo Rocldin facility.

113

Litigation Constellation Energy once the cases are finally concluded as to In the normal course of business, we are involved in various all defendants. We believe that we have meritorious defenses and legal proceedings. We discuss the significant matters below. intend to defend the actions vigorously. However, we cannot predict the timing, or outcome, of these cases, or their possible Western Power Markets effect on our, or BGE's, financial results.

City of Tacoma v. AEP, t aL,e-The City of Tacoma, on June 7, 2004, in the U.S. District Court, Western District of Asbestos Washington, filed a complaint against over 60 companies, Since 1993, BGE has been involved in several actions including Constellation Energy Commodities Group, Inc. concerning asbestos. The actions are based upon the theory of (CCG). The complaint alleges that the defendants engaged in "premises liability," alleging that BGE knew of and exposed manipulation of electricity markets resulting in prices for power individuals to an asbestos hazard. BGE and numerous other in the western power markets that were substantially above what parties are defendants in these cases.

market prices would have been in the absence of the alleged Approximately 509 individuals who were never employees unlawful contracts, combinations and conspiracy in violation of of BGE have pending claims each seeking several million dollars Section 1 of the Sherman Act. The complaint further alleges in compensatory and punitive damages. Cross-claims and third-that the total amount of damages is unknown, but is estimated party claims brought by other defendants may also be filed to exceed $175 million. On February 11, 2005, the Court against BGE in these actions. To date, most asbestos claims granted the defendants' motion to dismiss the action based on against us have been dismissed or resolved without any payment the Court's lack of jurisdiction over the claims in question. The and a small minority have been resolved for amounts that were plaintiff has appealed the dismissal of the action to the Ninth not material to our financial results. The remaining claims are Circuit Court of Appeals. We believe that we have meritorious currently pending in state courts in Maryland and Pennsylvania.

defenses to this action and intend to defend against it vigorously. BGE does not know the specific facts necessary to estimate However, we cannot predict the timing, or outcome, of this case, its potential liability for these claims. The specific facts BGE or its possible effect on our financial results. does not know include:

" the identity of BGE's facilities at which the plaintiffs Wholesale ElectricityAntitrust Cues allegedly worked as contractors, In connection with a proceeding originally filed in March 2002, " the names of the plaintiffs' employers, Reliant Energy Services (Reliant) and certain of its affiliates filed " the dates on which and the places where the exposure to join CCG and 29 other companies as cross-defendants in a allegedly occurred, and proceeding entitled Wholesale Electricity Antitrust Cases I and I1.

• the facts and circumstances relating to the alleged Motions to dismiss the claims filed against the original exposure.

defendants were recently granted and the original defendants Until the relevant facts are determined, we are unable to have dismissed the cross claims filed against CCG and the 29 estimate what our, or BGE's, liability might be. Although other cross defendants. Therefore, the claims against CCG in insurance and hold harmless agreements from contractors who this action are resolved. employed the plaintiffs may cover a portion of any awards in the actions, the potential effect on our, or BGE'S, financial results Mercury could be material.

Beginning in September 2002, BGE, Constellation Energy, and There has been no activity related to certain third-party several other defendants have been involved in numerous actions claims filed against BGE by Pittsburgh Corning Corp. (PCC) filed in the Circuit Court for Baltimore City, Maryland alleging since PCC filed bankruptcy in April 2000. In addition, we do mercury poisoning from several sources, including coal plants not believe that any amounts payable under claims made by formerly owned by BGE. The plants are now owned by a PCC would have a material effect on our, or BGE'S, financial subsidiary of Constellation Energy. In addition to BGE and results.

Constellation Energy, approximately 11 other defendants, consisting of pharmaceutical companies, manufacturers of CanadianEnvironmental Class Action vaccines, and manufacturers of Thimerosal have been sued. ChristopherM. Robinson, et. aL v. Ontario Power Generation Inc.,

Approximately 70 cases, involving claims related to et. aL-On June 30, 2005, three individuals filed a class action approximately 132 children, have been filed to date, with each in the Superior Court of Justice in Ontario, Canada against 21 claimant seeking $20 million in compensatory damages, plus companies, including Constellation Power Source punitive damages, from us. Generation, Inc. (CPSG), one of our subsidiaries. The complaint In a ruling applicable to all but six of the cases, involving alleges claims on behalf of residents of Ontario, Canada that claims related to approximately 49 children, the Circuit Court have allegedly suffered adverse health effects as a result of for Baltimore City dismissed with prejudice all claims against emissions of sulfur dioxide, nitrogen oxide, and particulate BGE and Constellation Energy and entered into a stay of the matter from approximately 60 different coal-fired power plants proceedings as they relate to other defendants. Plaintiffs may operating in Ontario, Michigan, Ohio, Pennsylvania, Kentucky, attempt to pursue appeals of the rulings in favor of BGE and and West Virginia. The complaint was not served on the 114

defendants as required by December 31, 2005, and thus, this $10.8 billion. Under the retrospective assessment program, we action is effectively dismissed without prejudice. can be assessed up to $503 million per incident at any commercial reactor in the country, payable at no more than Storage of Spent Nuclear Fuel $75 million per incident per year. This assessment also applies in The Nuclear Waste Policy Act of 1982 (NWPA) required the excess of our worker radiation claims insurance and is subject to federal government through the Department of Energy (DOE), inflation and state premium taxes. Claims resulting from to develop a repository for, and disposal of, spent nuclear fuel non-certified acts of terrorism are limited to the commercial and high-level radioactive waste. The NWPA and our contracts insurance discussed above, regardless of the number of nuclear with the DOE required the DOE to begin taking possession of plants affected. In addition, the U.S. Congress could impose spent nuclear fuel generated by nuclear generating units no later additional revenue-raising measures to pay claims.

than January 31, 1998. The DOE has stated that it will not meet that obligation until 2010 at the earliest. Worker Radiation Claims Insurance This delay has required that we undertake additional We participate in the American Nuclear Insurers Master Worker actions related to on-site fuel storage at Calvert Cliffs and Nine Program that provides coverage for worker tort claims filed for Mile Point, including the installation of on-site dry fuel storage radiation injuries. Effective January 1, 1998, this program was capacity at Calvert Cliffs. In January 2004, we filed a complaint modified to provide coverage to all workers whose nuclear-against the federal government in the United States Court of related employment began on or after the commencement date Federal Claims seeking to recover damages caused by the DOE's of reactor operations. Waiving the right to make additional failure to meet its contractual obligation to begin disposing of claims under the old policy was a condition for coverage under spent nuclear fuel by January 31, 1998. The cases are currently the new policy. We describe the old and new policies below:

stayed, pending litigation in other related cases. " Nuclear worker claims reported on or after January 1, In connection with our purchase of Ginna, all of Rochester 1998 are covered by a new insurance policy with a Gas & Electric Corporation's (RG&E) rights and obligations single industry aggregate limit of $300 million for related to recovery of damages from the DOE were assigned to radiation injury claims against all those insured by this us. However, we have an obligation to reimburse RG&E for up policy.

to the first $10 million in recovered damages.

• All nuclear worker claims reported prior to January 1, 1998 are still covered by the old policy. Insureds under Nuclear Insurance the old policies, with no current operations, are not We maintain nuclear insurance coverage for Calvert Cliffs, Nine required to purchase the new policy described on the Mile Point, and Ginna in four program areas: liability, worker previous page, and may still make claims against the old radiation, property, and accidental outage. These policies contain policies through 2007. If radiation injury claims under certain industry standard exclusions, including, but not limited these old policies exceed the policy reserves, all to, ordinary wear and tear, and war. policyholders could be retroactively assessed, with our In November 2002, the President signed into law the share being up to $6.3 million.

Terrorism Risk Insurance Act ("TRIA") of 2002. Under the The sellers of Nine Mile Point retain the liabilities for TRIA, property and casualty insurance companies are required to existing and potential claims that occurred prior to November 7, offer insurance for losses resulting from Certified acts of 2001. In addition, the Long Island Power Authority, which terrorism. Certified acts of terrorism are determined by the continues to own 18% of Unit 2 at Nine Mile Point, is Secretary of State and Attorney General and primarily arc based obligated to assume its pro rata share of any liabilities for upon the occurrence of significant acts of international terrorism. retrospective premiums and other premium assessments. RG&E, Our nuclear property and accidental outage insurance programs, the seller of Ginna, retains the liabilities for existing and as discussed later in this section, provide coverage for Certified potential claims that occurred prior to June 10, 2004. If claims acts of terrorism. under these policies exceed the coverage limits, the provisions of If there were an accident or an extended outage at any unit the Price-Anderson Act would apply.

of Calvert Cliffs, Nine Mile Point or Ginna, it could have a substantial adverse impact on our financial results. Nuclear PropertyInsurance Our policies provide $500 million in primary coverage at each Nuclear Liability Insurance nuclear plant-Calvert Cliffs, Nine Mile Point, and Ginna. In Pursuant to the Price-Anderson Act, we are required to insure addition, we maintain $1.77 billion of excess coverage at Ginna against public liability claims resulting from nuclear incidents to and $2.25 billion in excess coverage under a blanket excess the full limit of public liability. This limit of liability consists of program offered by the industry mutual insurer at both Calvert the maximum available commercial insurance of $300 million Cliffs and Nine Mile Point. Under the blanket excess policy, and mandatory participation in an industry-wide retrospective Calvert Cliffs and Nine Mile Point share $1.0 billion of the premium assessment program. The retrospective premium total $2.25 billion of excess property coverage. Therefore, in the assessment is $100.6 million per reactor, increasing the total unlikely event of two full limit property damage losses at Calvert amount of insurance for public liability to approximately Cliffs and Nine Mile Point, we would recover $4.5 billion 115

instead of $5.5 billion. This coverage currently is purchased coverage is up to $490.0 million per unit at Calvert Cliffs and through the industry mutual insurance company. If accidents at Ginna, $420.0 million for Unit 1 of Nine Mile Point, and plants insured by the mutual insurance company cause a $401.8 million for Unit 2 of Nine Mile Point. This amount can shortfall of funds, all policyholders could be assessed, with our be reduced by up to $98.0 million per unit at Calvert Cliffs and share being up to $92.3 million. $84.0 million for Nine Mile Point if an outage of more than Losses resulting from non-certified acts of terrorism are one unit is caused by a single insured physical damage loss.

covered as a common occurrence, meaning that if non-certified terrorist acts occur against one or more commercial nuclear Non-Nuclear Property Insurance power plants insured by our nuclear property insurance company Our conventional property insurance provides coverage of within a 12-month period, they would be treated as one event $1.0 billion per occurrence for Certified acts of terrorism as and the owners of the plants where the acts occurred would defined under the Terrorism Risk Insurance Act of 2002.

share one full limit of liability (currently $3.24 billion). Certified acts of terrorism are determined by the Secretary of State and Attorney General of the United States and primarily Accidental Nuclear Outage Insurance are based upon the occurrence of significant acts of international Our policies provide indemnification on a weekly basis for losses terrorism. Our conventional property insurance program also resulting from an accidental outage of a nuclear unit. Coverage provides coverage for non-certified acts of terrorism up to an begins after a 12-week deductible period and continues at 100% annual aggregate limit of $1.0 billion. If a terrorist act occurs at of the weekly indemnity limit for 52 weeks and then 80% of any of our facilities, it could have a significant adverse impact the weekly indemnity limit for the next 110 weeks. Our on our financial results.

3 Hedging Activities and Fair Value of Financial Instruments SFAS No. 133 Hedging Activities floating-rate swaps in "Interest expense" in the periods that the We are exposed to market risk, including changes in interest swaps settle.

rates and the impact of market fluctuations in the price and "Accumulated other comprehensive income" includes net transportation costs of electricity, natural gas, and other unrealized pre-tax gains on interest rate cash-flow hedges totaling commodities. $15.4 million at December 31, 2005 and $18.3 million at December 31, 2004. We expect to reclassify $2.9 million of Interest Rates pre-tax net gains on these cash-flow hedges from "Accumulated We use interest rate swaps to manage our interest rate exposures other comprehensive income" into "Interest expense" during the associated with new debt issuances and to optimize the mix of next twelve months. We had no hedge ineffectiveness on these fixed and floating-rate debt. The swaps used to manage our swaps.

exposure prior to the issuance of new debt are designated as During 2004, to optimize the mix of fixed and floating-rate cash-flow hedges under SFAS No. 133, with the effective debt, we entered into interest rate swaps qualifying as fair value portion of gains and losses, net of associated deferred income tax hedges relating to $450 million of our fixed-rate debt maturing effects, recorded in "Accumulated other comprehensive income in 2012 and 2015, and converted this notional amount of debt in our Consolidated Statements of Common Shareholders' to floating-rate. The fair value of these hedges was an unrealized Equity and Comprehensive Income and Consolidated Statements loss of $0.9 million at December 31, 2005 and was recorded as of Capitalization, in anticipation of planned financing an increase in our "Risk management liabilities" and a decrease transactions. We reclassify gains and losses on the hedges from in our "Long-term debt." The fair value of these hedges was an "Accumulated other comprehensive income" into "Interest unrealized gain of $13.3 million at December 31, 2004 and was expense" in our Consolidated Statements of Income during the recorded as an increase in our "Risk management assets" and periods in which the interest payments being hedged occur. "Long-term debt." We have not recognized any hedge The swaps used to optimize the mix of fixed and ineffectiveness on these interest rate swaps.

floating-rate debt are designated as fair value hedges under SFAS No. 133. We record any gains or losses on swaps that qualify for Commodity Prices fair value hedge accounting treatment, as well as changes in the Our merchant energy business uses a variety of derivative and fair value of the debt being hedged, in "Interest expense," and non-derivative instruments to manage the commodity price risk we record any changes in fair value of the swaps and the debt in of our competitive supply activities and our electric generation "Risk management assets and liabilities" and "Long-term debt" facilities, including power sales, fuel and energy purchases, gas in our Consolidated Balance Sheets. In addition, we record the purchased for resale, emission credits, weather risk, and the difference between interest on hedged fixed-rate debt and market risk of outages. In order to manage these risks, we may enter into fixed-price derivative or non-derivative contracts to 116

hedge the variability in future cash flows from forecasted sales of Regulated Gas Business energy and purchases of fuel and energy. The objectives for BGE uses basis swaps in the winter months (November through entering into such hedges include: March) to hedge its price risk associated with natural gas

" fixing the price for a portion of anticipated future purchases under its market-based rates incentive mechanism and electricity sales at a level that provides an acceptable under its off-system gas sales program. BGE also uses return on our electric generation operations, fixed-to-floating and floating-to-fixed swaps to hedge its price

" fixing the price of a portion of anticipated fuel risk associated with its off-system gas sales. The fixed portion purchases for the operation of our power plants, represents a specific dollar amount that BGE will pay or receive,

" fixing the price for a portion of anticipated energy and the floating portion represents a fluctuating amount based purchases to supply our load-serving customers, and on a published index that BGE will receive or pay. BGE's

" fixing the price for a portion of anticipated sales of regulated gas business internal guidelines do not permit the use natural gas to customers. of swap agreements for any purpose other than to hedge price The portion of forecasted transactions hedged may vary risk.

based upon management's assessment of market, weather, operational, and other factors. Fair Value of Financial Instruments At December 31, 2005, our merchant energy business had The fair value of a financial instrument represents the amount at designated certain fixed-price forward contracts as cash-flow which the instrument could be exchanged in a current hedges of forecasted sales of energy and forecasted purchases of transaction between willing parties, other than in a forced sale or fuel and energy for the years 2006 through 2015 under SFAS liquidation. Significant differences can occur between the fair No. 133. Our merchant energy business had net unrealized value and carrying amount of financial instruments that are pre-tax losses on these cash-flow hedges recorded in recorded at historical amounts. We use the following methods "Accumulated other comprehensive income" of $517.1 million at and assumptions for estimating fair value disclosures for financial December 31, 2005 and $103.8 million at December 31, 2004. instruments:

We expect to reclassify $434.7 million of net pre-tax gains on

• cash and cash equivalents, net accounts receivable, other cash-flow hedges from "Accumulated other comprehensive current assets, certain current liabilities, short-term income" into earnings during the next twelve months based on borrowings, current portion of long-term debt, and the market prices at December 31, 2005. However, the actual certain deferred credits and other liabilities: because of amount reclassified into earnings could vary from the amounts their short-term nature, the amounts reported in our recorded at December 31, 2005, due to future changes in Consolidated Balance Sheets approximate fair value, market prices. " investments and other assets: the fair value is based on Additionally, for cash-flow hedges settled by physical quoted market prices where available, and delivery of the underlying commodity, "Reclassification of net " long-term debt: the fair value is based on quoted market gains on hedging instruments from OCI to net income" prices where available or by discounting remaining cash represents the fair value of those derivatives, which is realized flows at current market rates.

through gross settlement at the contract price. In 2005, we We show the carrying amounts and fair values of financial recognized $19.4 million of pre-tax losses in earnings related to instruments included in our Consolidated Balance Sheets in the cash-flow hedge ineffectiveness. During 2005, we terminated a following table.

contract previously designated as a cash-flow hedge. The forecasted transaction originally hedged is no longer probable At December31, 2005 2004 and as a result we recognized a pre-tax loss of $6.1 million. Carrying Fair Carrying Fair Amount Value Amount Value Our merchant energy business also enters into natural gas (In millions) storage contracts under which the gas in storage qualifies for fair Investments and value hedge accounting treatment under SFAS No. 133. During other assets-2005, we had unrealized pre-tax gains of $2.3 million and Constellation unrealized pre-tax losses of $4.5 million due to hedge Energy $1,362.1 $1,362.3 $1,190.0 $1,191.2 ineffectiveness, and the resulting pre-tax net loss of $2.2 million Fixed-rate long-was recognized into earnings during 2005. We record changes in term debt:

fair value of these hedges as a component of "Fuel and Constellation Energy 4,169.3 4,379.3 4,468.5 4,979.7 purchased energy expenses" in our Consolidated Statements of BGE 1,364.6 1,376.4 1,404.3 1.468.2 Income. Variable-rate long-term debt:

Constellation Energy 699.3 699.3 835.6 835.6 BGE 97.4 97.4 99.3 99.3 117

14 Stock-Based Compensation Under our long-term incentive plans, we granted stock options, 2005 2004 2003 performance and service-based restricted stock, performance- Risk-free interest rate 4.10% 3.15% 2.92%

based units, and equity to officers, key employees, and members Expected life (in years) 2.9* 5.0 5.0 of the Board of Directors. Under the plans, we can grant up to Expected market price volatility a total of 18,000,000 shares. At December 31, 2005, we had factor 21.3% 23.7% 32.0%

stock options, restricted stock, and stock unit grants outstanding Expected dividend yield 3.0% 3.0% 3.3%

as discussed below. We may issue new shares, reuse forfeited Includes 2.0 million fully vested options grantedin December 2005 shares, or buy shares in the market in order to deliver shares to that will be cancelled upon a change in control if our pending merger employees for our equity grants. BGE officers and key employees with FPL Group is consummatedfor which an expected life of one participate in our stock-based compensation plans. The expense year was used to value the grant. Excluding this grant, we used a recognized by BGE in 2005, 2004, and 2003 was not material weighted-average expected life assumption of5 yearsfor 2005 grants.

to BGE's financial results.

We use the historical data related to stock option exercises Certain awards accounted for as equity grants under our in order to estimate the expected life of our stock options. We long-term incentive plans provide for accelerated vesting and also use historical data in order to estimate the volatility factor cash settlement in the event of a change in control. If the (measured on a daily basis) for a period equal to the duration of pending merger with FPL Group becomes probable of occurring, the expected life of option awards. We believe that the use of we will be required to account for these awards as liabilities under SFAS No. 123R and remeasure them at fair value each historical data to estimate these factors provides a reasonable reporting period until they are settled. We discuss the pending basis for our assumptions. The risk-free interest rate for the merger with FPL Group in more detail in Note 15. periods within the expected life of the option is based on the U.S Treasury yield curve in effect and the expected dividend Non-Qualified Stock Options yield is based on our current estimate for dividend payout at the Options are generally granted with an exercise price equal to the time of grant. We disclose the pro-forma effect on net income market value of the common stock at the date of grant, become and earnings per share for the periods prior to adoption of SFAS vested over a period up to three years (expense recognized in No. 123R in Note 1.

tranches), and expire ten years from the date of grant. The fair Summarized information for our stock option grants is as value of our stock-based awards were estimated as of the date of follows:

grant using the Black-Scholes option pricing model based on the following weighted-average assumptions:

2005 2004 2003 Weighted- Weighted- Weighted-Average Average Average Shares Exercise Price Shares Exercise Price Shares Exercise Price (Shares in thousands)

Outstanding, beginning of year 7,365 $31.62 7,117 $29.53 6,081 $29.65 Granted with exercise prices:

At fair market value 3,840 54.94 1,640 39.60 1,485 29.24 Greater than fair market value . - - 9 28.53 Total granted 3,840 54.94 1,640 39.60 1,494 29.24 Exercised (3,935) 29.32 (834) 28.49 (267) 27.92 Forfeited/expired (98) 42.19 (558) 33.09 (191) 33.28 Outstanding, end of year 7,172 $45.24 7,365 $31.62 7,117 $29.53 Exercisable, end of year 4,022 $45.31 3,844 $29.99 3,169 $29.89 Weighted-average fair value per share of options granted with exercise prices:

At fair market value $ 7.13 $ 7.22 $ 6.80 Greater than fair market value -

-- 5.56 118

The total intrinsic value realized by participants on We recorded compensation expense related to our options exercised during the years ended December 31, 2005 restricted stock awards of $28.2 million in 2005, $17.0 million was $109.8 million, 2004 was $10.5 million, and 2003 was in 2004, and $16.4 million in 2003. Summarized share

$1.8 million. We realized a tax benefit of $43.4 million in information for our restricted stock awards is as follows:

2005, $4.2 million in 2004, and $0.7 million in 2003 on the 2005 2004 2003 intrinsic value realized by participants on option exercises. In (Sharer in thousands) addition, we received cash of $35.3 million in 2005, Outstanding, beginning of year 1,223 752 314

$23.7 million in 2004, and $7.5 million in 2003 for the Granted 485 1,002 555 exercise price associated with stock option exercises. The total Released to participants (359) (467) (109) fair value of shares that vested in 2005 was $232.0 million, in Canceled (77) (64) (8) 2004 was $59.0 million, and in 2003 was $69.4 million. As of Outstanding, end of year 1,272 1,223 752 December 31, 2005, we had $10.4 million of unrecognized compensation cost related to the unvested portion of Weighted-average fair value of restricted stock granted $51.23 $38.83 $30.53 outstanding stock option awards expected to be recognized within a two-year period. Total fair value of shares for The following table summarizes additional information which restriction has lapsed (in about stock options outstanding at December 31, 2005 (stock millions) $ 19.0 $ 18.8 $ 3.8 options in thousands):

As of December 31, 2005, wve had $16.7 million of Outstanding Exercisable Weighted- unrecognized compensation cost related to the unvested portion Average of outstanding restricted stock awards expected to be Range of Aggregate Aggregate Remaining recognized within a two-year period. At December 31, 2005, Exercise Stock Intrinsic Stock Intrinsic Contractual Prices Options Value Options Value life we have recorded in "Common shareholders' equity" (In millons) (In millions) (In yean) approximately $21 million for the unvested portion of service-

$20.00 - $30.00 887 $25.6 538 $15.6 7.2 based restricted stock granted from 2001 until 2005 to officers

$30.00- $40.00 2,416 51.4 1,481 34.6 6.7 and other employees that is contingently redeemable in cash

$40.00 - $50.00 66 1.1 22 0.4 8.3 upon a change in control.

$50.00- $60.00 3,803 11.1 1,981 - 7.7 7,172 $89.2 4,022 $50.6 Performance-Based Units In accordance with SFAS No. 123R, we recognize Restricted Stock Awards compensation expense ratably for our performance-based In addition to stock options, we issue common stock based on awards, which are classified as liability awards, for which the meeting certain service goals. This stock vests to participants at fair value of the award is remeasured at each reporting period.

various times ranging from one to five years if the service goals Each unit is equivalent to $1 in value and cliff vests at the end are met. In accordance with SFAS No. 123R, we account for of a three-year service and performance period. The level of our service-based awards as equity awards, whereby we payout is based on the achievement of certain performance recognize the value of the market price of the underlying stock goals at the end of the three-year period and at least 50% of on the date of grant to compensation expense over the service any payouts will be settled in cash, and the other 50% may be period either ratably or in tranches (depending if the award has settled in either stock or cash at our discretion. We recorded cliff or graded vesting). compensation expense of $7.0 million in 2005, $2.9 million in 2004, and no expense in 2003 for these awards. No awards were settled during the year, and as of December 31, 2005 we had $12.2 million of unrecognized compensation cost related to the unvested portion of outstanding performance-based unit awards expected to be recognized within a two-year period.

Equity-Based Grants We recorded compensation expense of $0.5 million in 2005,

$0.5 million in 2004, and $0.4 million in 2003 related to equity-based grants to members of the Board of Directors.

119

15 Merger and Acquisitions Pending Merger with FPL Group, Inc. Acquisition of Cogenex On December 18, 2005, Constellation Energy entered into an In April 2005, we acquired Cogenex Corporation from Alliant Agreement and Plan of Merger with FPL Group. Immediately Energy Corporation. We include Cogenex with our other prior to the completion of the merger, each share of nonregulated businesses and have included their results in our Constellation Energy will be split into 1.444 shares of consolidated financial statements since the date of acquisition.

Constellation Energy common stock and cash will be paid in Cogenex is a North American energy services firm providing lieu of fractional shares. At closing, each share of common stock consulting and technology solutions to industrial, institutional, of FPL Group issued and outstanding will be exchanged for 1.0 and governmental customers. We acquired 100% ownership of share of common stock of Constellation Energy. As a result of Cogenex for $35.2 million. We acquired cash of $14.4 million the stock split and merger and assuming no conversion of any as part of the purchase.

other convertible securities of FPL Group or Constellation Our preliminary purchase price allocation for the net assets Energy, it is expected that Constellation Energy stockholders will acquired is as follows:

own approximately 40% of the combined company's outstanding shares of common stock immediately following the merger and At April 1, 2005 FPL Group stockholders will own approximately 60% of the (In millions) common stock of the combined company's outstanding shares of Cash $ 14.4 common stock. Other Current Assets 11.3 The merger agreement contains certain termination rights Total Current Assets 25.7 for both Constellation Energy and FPL Group and under Net Property, Plant and Equipment specified circumstances Constellation Energy may be required to Other Assets 36.0 pay FPL Group a termination fee of $425 million and FPL Total Assets Acquired 61.7 Group may be required to pay Constellation Energy a Current Liabilities (7.3) termination fee of $650 million. In addition, under specified Deferred Credits and Other liabilities (19.2) circumstances each party may be obligated to reimburse the Net Assets Acquired $ 35.2 other party for up to $40 million of expenses, which would reduce the amount of any required termination fee payable by Currently, the purchase price remains subject to certain that party. Furthermore, under certain limited circumstances a adjustments, which could impact our purchase price allocation.

parry whose board of directors has changed or withdrawn its We believe that the pro-forma impact of the Cogenex recommendation in favor of the merger may be required to pay acquisition would not have been material to our results of the other party $100 million. These payments would also reduce operations in 2005, 2004, and 2003.

the amount of any other required termination fee payable by that party. Acquisition of Working Interests In Gas Producing Fields The merger agreement has been unanimously approved by In June 2005, we acquired working interests in gas producing both companies' boards of directors but completion of the fields in Texas and Alabama for approximately $211 million in merger is contingent upon, among other things, the approval of cash and the assumption of below-market natural gas swaps and the transaction by shareholders of both companies and receipt of other liabilities totaling approximately $18 million. At the time required regulatory approvals. The companies anticipate of acquisition, these working interests had independently obtaining all necessary approvals before the end of 2006. estimated proved reserves of approximately 216 billion cubic feet The merger will be accounted for as a purchase under equivalent. The Texas asset acquisition was for approximately a accounting principles generally accepted in the United States of 70% working interest and the Alabama asset acquisition was for America. Under the purchase method of accounting, the assets a 100% working interest. We accounted for this transaction as and liabilities of Constellation Energy will be recorded, as of the an asset acquisition and include these working interests in our completion of the merger, at their respective fair values and merchant energy business segment.

added to those of FPL Group. The reported financial condition and results of operations of Constellation Energy after Acquisition of Ginna completion of the merger will reflect Constellation Energy's On June 10, 2004, we completed our purchase of the Ginna balances and results after completion of the merger, but will not nuclear facility, which is located in Ontario, New York from be restated retroactively to reflect the historical financial position RG&E. Ginna consists of a 498 megawatt reactor that entered or results of operations of Constellation Energy. service in 1970 and is licensed to operate until 2029.

In 2005, we expensed $17.0 million, of which BGE We purchased 100 percent of Ginna for $457.3 million recorded $5.4 million, of external costs incurred prior to the including direct costs associated with the acquisition, of which execution of the merger agreement. We estimate our total $430.0 million was paid in cash at closing and the remaining transaction costs will be approximately $40 million.

120

$27.3 million was paid during the second half of 2004. RG&E Acquisition of Blackhawk Energy Services and Kartex also transferred to us $200.8 million in decommissioning funds. Energy Management We will sell 90 percent of Ginna's output back to RG&E at On October 22, 2003, we completed our purchase of Blackhawk an average price of nearly $44 per megawatt-hour until Energy Services (Blackhawk) and Kaztex Energy Management June 2014 under a unit contingent power purchase agreement (if (Kaztex). We include Blackhawk and Kaztex, part of our retail the output is not available because the plant is not operating, gas operation, in our merchant energy business segment and there is no requirement to provide output from other sources). have included their results in our consolidated financial The acquisition of Ginna was immediately accretive to earnings. statements since the date of acquisition. Blackhawk and Kaztex We accounted for this transaction as an asset acquisition are providers of natural gas and electricity services.

and included Ginna in our merchant energy business segment. On an unaudited pro-forma basis, had the acquisition of Our purchase price allocation for the net assets acquired is as Blackhawk and Kaztex occurred on the first day of 2003, our follows: nonregulated revenues and total revenues would have been as follows:

At June 10, 2004 Year Ended December31. 2003 (In millions)

(In millons)

Current Assets $ 27.9 Nuclear Decommissioning Trust Fund 200.8 Nonregulated revenues Nuclear Fuel 14.5 As reported $6,819.9 Pro-forma 7,174.8 Net Property, Plant and Equipment 382.8 Total revenues Intangible Assets (details below) 38.8 As reported 9,454.1 Other Assets 124.0 Pro-forma 9,809.0 Total Assets Acquired 788.8 We believe that the pro-forma impact on "Income before Current Liabilities (20.8) cumulative effect of change in accounting principle," "Net Asset Retirement Obligations (177.3) income," and "Earnings per common share" would not have Deferred Credits and Other Liabilities (133.4) been material had the acquisition of Blackhawk and Kaztex Net Assets Acquired $ 457.3 occurred on the first day of the year presented.

The intangible assets acquired consist of the following:

Weighted-Average Description Amnount Useful Life (In millions) (In years)

Operating procedures and manuals $26.1 25 Permits and licenses 25 Software $8. 5 Total intangible assets $38.8 121

6 Related Party Transactions-BGE Income Statement The following table presents the costs Constellation Energy BGE provides standard offer service to those customers that do charged to BGE in each period.

not choose an alternate supplier. Our wholesale marketing and risk management operation provided BGE with the energy and Year ended December 31, 2005 2004 2003 capacity required to meet its commercial and industrial standard (In millions) offer service obligations through June 30, 2004 and provides the Charges to BGE $130.3 $99.8 $84.0 energy and capacity required to meet its residential standard offer service obligations through June 30, 2006. Bidding to Balance Sheet supply BGE's standard offer service to commercial and industrial BGE participates in a cash pool under a Master Demand Note customers beyond June 30, 2004, and to residential customers agreement with Constellation Energy. Under this arrangement, beyond June 30, 2006, will continue to occur from time to time participating subsidiaries may invest in or borrow from the pool through a competitive bidding process approved by the at market interest rates. Constellation Energy administers the Maryland PSC. Our wholesale marketing and risk management pool and invests excess cash in short-term investments or issues operation is supplying a portion of BGE's standard offer service commercial paper to manage consolidated cash requirements.

obligation to commercial and industrial customers. Under this arrangement, BGE had borrowed $3.2 million at The cost of BGE's purchased energy from nonregulated December 31, 2005 and had invested $127.9 million at affiliates of Constellation Energy to meet its standard offer December 31, 2004.

service obligation was as follows: BGE's Consolidated Balance Sheets include intercompany amounts related to corporate functions performed at the Year Ended December31, 2005 2004 2003 Constellation Energy holding company, BGE's purchases to meet (In milons) its standard offer service obligation, BGE's charges to Electricity purchased for resale expenses $805.9 $948.9 $1,023.4 Constellation Energy and its nonregulated affiliates for certain services it provides them, and the participation of BGE's In addition, Constellation Energy charges BGE for the employees in the Constellation Energy pension plan.

costs of certain corporate functions. Certain costs are directly We believe our allocation methods are reasonable and assigned to BGE. We allocate other corporate function costs approximate the costs that would be charged to unaffiliated based on a total percentage of expected use by BGE. We believe entities.

this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity.

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7 Quarterly Financial Data (Unaudited)

Our quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair statement. Our business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months.

Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.

2005 Quarterly Damt-Constellation Energy 2005 Quarterly Data-BGE Eaamings PCr Share Income from from Coi ntinuing Continuing 0 erations Operations an' I Before and Before Cuimulative Cumulative Earnings EFfrets of Earnings Per Effects of Applicable Chsanges in Share of Earnings Income Changes in to Accounting Common Income Ap li a1,l from Accounting Common Pesnciples- Stock- from to .oemmon Revenues Operations Principles Stock Diluted Diluted Revenues Operations Stock (In miora, except per share amounts) (In millions)

Quarter Ended Quarter Ended March 31" $ 3,572.0 $ 221.9 $118.6 $120.7 $0.66 $0.68 March31 $ 857.3 $ 143.7 $ 71.0 June 30" 3,478.5 209.8 117.8 121.7 0.66 0.68 June 30 610.3 64.4 23.6 September 30 4,922.4 317.0 184.1 185.5 1.02 1.03 September 30 742.7 94.9 42.4 December 31 5,159.1 309.4 186.2 195.2 1.04 1.09 December 31 799.0 93.5 38.8 Year Ended Year Ended December 31 $17,132.0 $1,058.1 $606.7 $623.1 $3.38 $3.47 December 31 $3,009.3 $ 396.5 $ 175.8 The sum of the quarterly earningsper share amount may not equal the totalfor the year due to the effects ofrounding and dilution as a during the year.

result of issuing common shares First quarter results include:

" a $1.7 million gain after-tax for the discontinued operations related to our other nonregulated international investments, and

" a $0.4 million gain after-tax for the discontinued operations related to our Oleander facility.

Second quarter results include:

" a $2.6 million gain after-tax for the discontinued operations related to our Oleander facility, and

" a $1.2 million gain after-tax income for discontinued operations related to our other nonregulated international investments.

Third quarter results include:

" workforce reduction costs totaling $2.3 million after-tax, and

" a $1.6 million gain after-tax for discontinued operations related to our other nonregulated international investments.

Fourth quarter results include:

" a $16.1 million gain after-tax for discontinued operations related to our other nonregulated international investments,

" merger related transaction costs totaling $15.6 million after-tax, of which BGE recorded $5.0 million after-tax,

" a $7.4 million after-tax loss for the cumulative effect of adopting FIN 47,

" workforce reduction costs totaling $0.4 million after-tax, and

" a $0.2 million after-tax gain for the cumulative effect of adopting SFAS No. 123R.

We discuss these items in Note 2.

• Due to the reclassificationof our other nonregulatedinternationalinvestments to discontinued operations, we have reclassifiedcertain amounts previously reported in ourfirst and second quarter Form 1O-Qs. The following is a reconciliationof amounts previously reported to amounts currently presentedfor those items.

For the quarter ended March 31. 2005 June 30, 2005 As Discontinued Discontinued Reported Operations Reclassified As Reported Operations Reclassified

, (In milions, except per share amounts)

Revenues $3,629.8 $(57.8) $3,572.0 $3,548.8 $(70.3) $3,478.5 Income from Operations 230.8 (8.9) 221.9 218.3 (8.5) 209.8 Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles 120.3 (1.7) 118.6 119.0 (1.2) 117.8 Earnings Per Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles - Diluted 0.67 (0.01) 0.66 0.66 -- 0.66 123 i

2004 Quarterly Data-Constellation Energy Earnings Earnings 2004 Quarterly Data-BGE Income Earnings Applicable Per Share Per Share from of Earnings Income from to Continuing Common Income from toApplicable tommon from Continuing Common Operations- Stock-Revenues Operations Operations Stock IDiluted Diluted Revenues Operations Stock (In milions, cept per u/are amounts) (In millions)

Quarter Ended Quarter Ended March 3 1 $ 2,976.0 $ 224.7 $109.1 $ 66.2 $0.64 $0.39 March 31 $ 803.9 $149.8 $ 72.7 June 30' 2,730.8 182.8 126.7 128.2 0.75 0.76 June 30 589.8 65.6 21.9 September 30 3,358.8 382.2 204.8 210.4 1.16 1.19 September 30 657.3 77.1 28.1 December 31 3,220.8 235.5 126.2 134.9 0.71 0.76 December 31 673.7 78.9 30.4 Year Ended Year Ended December 31 $12,286.4 $1,025.2 $566.8 $539.7 $3.28 $3.12 December 31 $2,724.7 $371.4 $153.1 The sum of the quarterly earningsper share amounts may not equal the totalfor the year due to the effects of rounding and dilution as a result of issuing common shares during the year.

First quarter results include:

" a $46.3 million loss after-tax for the discontinued operations of our Hawaiian geothermal facility,

" a $2.2 million gain after-tax for the discontinued operations of our Oleander facility, and

• a $1.2 million gain after-tax for the discontinued operations of our other nonregulated international investments.

Second quarter results include:

• a recognition of 2003 synthetic fuel tax credits of $35.9 million after-tax,

" a $2.7 million loss after-tax for the discontinued operations of our Hawaiian geothermal facility,

• a $2.7 million gain after-tax for the discontinued operations of our Oleander facility, and

" a $1.5 million gain after-tax for the discontinued operations of our other nonregulated international investments.

Third quarter results include:

" a $0.2 million loss after-tax for the discontinued operations of our Hawaiian geothermal facility,

" a $4.6 million gain after-tax for the discontinued operations of our Oleander facility, and

• a $1.2 million gain after-tax for the discontinued operations of our other nonregulated international investments.

Fourth quarter results include:

" workforce reduction costs totaling $5.9 million after-tax,

" a $5.5 million gain after-tax for discontinued operations of our other nonregulated international investments,

" a $3.1 million gain after-tax for discontinued operations of our Oleander facility, and

" a $0.1 million gain after-tax for the discontinued operations of our Hawaiian geothermal facility.

We discuss these items in Note 2.

Due to the reclassificationof our other nonregulated internationalinvestments to discontinued operations, we have reclassified certain amounts previously reported in our first and second quarter Form lO-Qs. The following is a reconciliation ofamounts previously reported to amounts currently presentedfor those items.

For shequarter ended March 31, 2004 June 30. 2004 As Discontinued Discontinued Reported Operations Reclassified As Reported Operations Reclassified (In millions, grcept per share amounts)

Revenues $3,029.6 $(53.6) $2,976.0 $2,787.3 $(56.5) $2,730.8 Income from Operations 232.3 (7.6) 224.7 191.9 (9.1) 182.8 Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles 110.3 (1.2) 109.1 128.2 (1.5) 126.7 Earnings Per Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles-Diluted 0.65 (0.01) 0.64 0.76 (0.01) 0.75 124

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.

Item 9A. Controls and Procedures Evaluation of Disclosure Controls and Procedures The principal executive officers and principal financial officer of both Constellation Energy and BGE have evaluated the effectiveness of the disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of December 31, 2005 (the "Evaluation Date"). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, Constellation Energy's and BGE's disclosure controls and procedures are effective.

Internal Control Over FinancialReporting Constellation Energy maintains a system of internal control over financial reporting as defined in Exchange Act Rule 13a-15(f).

Constellation Energy's Management Report on Internal Control Over Financial Reporting is included in Item 8. FinancialStatements and Supplementary Data included in this report. As BGE is not an accelerated filer as defined in Exchange Act Rule 12b-2, it is not required to provide a report of management on the effectiveness of its internal control over financial reporting as of December 31, 2005, but will be required to do so as of December 31, 2007.

Changes In Internal Control During the quarter ended December 31, 2005, there has been no change in either Constellation Energy's or BGE's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, either Constellation Energy's or BGE's internal control over financial reporting.

Item 9B. Other Information None.

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PART III Item 11. Executive Compensation BGE meets the conditions set forth in General The information required by this item will be either set Instruction I(1)(a) and (b) of Form 10-K for a reduced forth under Directors'Compensation, Executive disclosure format. Accordingly, all items in this section Compensation, Common Stock Performance Graph and related to BGE are not presented. Report of Compensation Committee on Executive Compensation in the Proxy Statement and incorporated Item 10. Directors and Executive Officers of the herein by reference or set forth in an amendment to Registrant this Form 10-K.

The information required by this item with respect to directors will be either set forth under Election of Constellation Energy Directors in the Proxy Statement and incorporated herein by reference or set forth in an amendment to this Form 10-K.

The information required by this item with respect to executive officers of Constellation Energy Group, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, is set forth following Item 4 of Part I of this Form 10-K under Executive Officers of the Registrant.

Iern 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters The additional information required by this item will be either set forth under Security Ownership in the Proxy Statement and incorporated herein by reference or set forth in an amendment to this Form 10-K.

Equity Compensation Plan Information The following table reflects our equity compensation plan information as of December 31, 2005:

(a) (b) (c)

Number of securities Number of securities remaining to be issued upon Weighted-average available for future issuance exercise of exercise price of under equity compensation outstanding options, outstanding options, plans (excluding securities Plan Category warrants, and rights warrants, and rights reflected in item (a))

(In thousands) (In thousands)

Equity compensation plans approved by security holders 5,100 $47.66 2,688 Equity compensation plans not approved by security holders 2,072 $39.29 1,007 Total 7,172 $45.24 3,695 The plans that do not require shareholder approval are the Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan (Designated as Exhibit No. 10(v)) and the Constellation Energy Group, Inc. Management Long-Term Incentive Plan (Designated as Exhibit No. 10(w)). A brief description of the material features of each of these plans is set forth on the next page.

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2002 Senior Management Long-Term Incentive Plan The 2002 Senior Management Long-Term Incentive Plan was effective May 24, 2002. Grants under the plan may be made to employees who are officers of Constellation Energy or hold senior management level or key employee positions with Constellation Energy or its subsidiaries. Under the plan, the Board of Constellation Energy has authorized the issuance of up to 4,000,000 shares of Constellation Energy common stock in connection with the grant of stock options, performance and service-based restricted stock and restricted stock units, performance units, stock appreciation rights, dividend equivalents and other equity awards. Any shares covered by an award that is forfeited or canceled, expires or is settled in cash, including the settlement of tax withholding obligations using shares, will become available for issuance under the plan. Shares delivered under the plan may be authorized and unissued shares, shares held in treasury or shares purchased on the open market in accordance with the applicable securities laws. Restricted stock, restricted stock unit, and performance unit award payouts will be accelerated and stock options and stock appreciation rights gains will be paid in cash in the event of a change in control, as defined in the plan. The plan is administered by Constellation Energy's Chief Executive Officer.

Management Long-Term Incentive Plan The Management Long-Term Incentive Plan was effective February 1, 1998. Grants under the plan may be made to employees of Constellation Energy who hold a management level position and other employees of Constellation Energy and its subsidiaries as may be designated by Constellation Energy's Chief Executive Officer. Under the plan, the Board of Constellation Energy has authorized the issuance of up to 3,000,000 shares of Constellation Energy common stock in connection with the grant of stock options, performance and service-based restricted stock and restricted stock units, performance units, stock appreciation rights and dividend equivalents. The number of shares available for issuance under the plan includes shares subject to awards that have lapsed or terminated. Shares delivered under the plan may be authorized and unissued shares, shares held in treasury or shares purchased on the open market in accordance with applicable securities laws. Restricted stock, restricted stock unit, and performance unit award payouts will be accelerated and stock options and stock appreciation rights will become fully exercisable in the event of a change in control, as defined by the plan. The plan is administered by Constellation Energy's Chief Executive Officer.

Rem 13. Certain Relationships and Related Transactions The additional information required by this item will be either set forth under Certain Relationships and Related Transactions in the Proxy Statement and incorporated herein by reference or set forth in an amendment to this Form 10-K.

Item 14. Principal Accountant Fees and Services The information required by this item will be either set forth under Ratification ofAppointment of PricewaterhouseCoopersLLP as Independent RegisteredPublic Accounting Firmfor 2006 in the Proxy Statement and incorporated herein by reference or set forth in an amendment to this Form 10-K.

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PART IV Item 15. Exhibits and Financial Statement Schedules (a) The following documents are filed as a part of this Report:

1. Financial Statements:

Reports of Independent Registered Public Accounting Firm dated February 22, 2006 of PricewaterhouseCoopers LLP Consolidated Statements of Income-Constellation Energy Group for three years ended December 31, 2005 Consolidated Balance Sheets-Constellation Energy Group at December 31, 2005 and December 31, 2004 Consolidated Statements of Cash Flows-Constellation Energy Group for three years ended December 31, 2005 Consolidated Statements of Common Shareholders' Equity and Comprehensive Income-Constellation Energy Group for three years ended December 31, 2005 Consolidated Statements of Capitalization-Constellation Energy Group at December 31, 2005 and December 31, 2004 Consolidated Statements of Income-Baltimore Gas and Electric Company for three years ended December 31, 2005 Consolidated Statements of Comprehensive Income-Baltimore Gas and Electric Company for three years ended December 31, 2005 Consolidated Balance Sheets-Baltimore Gas and Electric Company at December 31, 2005 and December 31, 2004 Consolidated Statements of Cash Flows-Baltimore Gas and Electric Company for three years ended December 31, 2005 Notes to Consolidated Financial Statements

2. Financial Statement Schedules:

Schedule II-Valuation and Qualifying Accounts Schedules other than Schedule II are omitted as not applicable or not required.

3. Exhibits Required by Item 601 of Regulation S-K.

Exhibit Number

• 2 -- Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 to the Registration Statement on Form S-4 dated March 3, 1999, File No. 33-64799.)

• 2(a) - Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)

• 2(b) - Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.)

• 2(c) - Agreement and Plan of Merger, dated December 18, 2005, by and among FPL Group, Inc.,

Constellation Energy Group, Inc. and CF Merger Corporation. (Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated December 19, 2005, File Nos. 1-12869 and 1-1910.)

• 3(a) - Articles of Amendment and Restatement of the Charter of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Exhibit No. 99.2 to the Current Report on Form 8-K dated April 30, 1999, File No. 1-1910.)

• 3(b) - Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999.

(Designated as Exhibit No. 3(a) to the Quarterly Report on Form 10-Q for the quarter ended June 30,

.1999, File Nos. 1-12869 and 1-1910.)

• 3(c) - Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999.

(Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.)

• 128

• 3(d) - Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 to the Quarterly Report on Form IO-Q for the quarter ended September 30, 1996, File No. 1-1910.)

• 3(e) - Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 20, 2001.

(Designated as Exhibit No. 3(e) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)

• 3(f) - Bylaws of Constellation Energy Group, Inc., as amended to February 27, 2004. (Designated as Exhibit 3(a) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)

• 3(g) - Bylaws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, File No. 1-1910.)

• 4(a) - Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 dated March 29, 1999, File No. 333-75217.)

• 4(b) - First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003. (Designated as Exhibit No. 4(b) to the Registration Statement on Form S-3 dated January 24, 2003, File No. 333-102723.)

• 4(c) - Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 1995, File No. 1-1910); and the following Supplemental Indentures between BGE and Bankers Trust Company, Trustee:

Exhibit Dated File No. Designated In Number

• January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii)

• February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i)

• March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii)

• March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii)

• April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4

• July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a)

• October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4

• June 15, 1996 1-1910 (Form 10-Q dated August 13, 1996) 4

• 4(d) - Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3, File No. 2-98443); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated as Exhibit 4(a) to the Current Report on Form 8-K, dated November 13, 1987, File No. 1-1910) and as of January 26, 1993 (Designated as Exhibit 4(b) to the Current Report on Form 8-K, dated January 29, 1993, File No. 1-1910.)

• 4(e) - Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures. (Designated as Exhibit 4(d) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)

• 4(f) - Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures. (Designated as Exhibit 4 (e) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)

• 4(g) - Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)

• 4(h) - Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)

• 4(i) - Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.)

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• 10(a) - Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated.

(Designated as Exhibit No. 10(a) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)

• 10(b) - Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.)

"10(c) - Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated.

(Designated as Exhibit No. 10(c) to the Annual Report on Form 10-K for the year ended December 31, 2002, File Nos. 1-12869 and 1-1910.)

'10(d) - Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit 10(d) to the Annual Report on Form 10-K for the year ended December 31, 2004, File Nos. 1-12869 and 1-1910.)

110(e) - Compensation agreements between Constellation Energy Group, Inc. and E. Follin Smith (Attachment 1

- Employment Agreement; Attachment 2 - Severance Agreement (Attachment 2 superseded by amended and restated change in control severance agreement filed as Exhibit 10(y) to this Report.)(Designated as Exhibit 10(c) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)

10(f) - Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and Thomas V. Brooks.

• 10(g) - Grantor Trust Agreement Dated as of February 27, 2004 between Constellation Energy Group, Inc. and Citibank, NA. (Designated as Exhibit No. 10(d) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)

• 10(h) - Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and Mayo A. Shattuck Ill. (Designated as Exhibit 10.2 to the Current Report on Form 8-K dated December 19, 2005, File Nos. 1-12869 and 1-1910.)

• 10(i) - Grantor Trust Agreement dated as of February 27, 2004 between Constellation Energy Group, Inc. and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File Nos. 1-12869 and 1-1910.)

• 10(j) - Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2000, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)

-10(k) - Full Requirements Service Agreement between Constellation Power Source, Inc. and Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(a) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)

-10(l) - Full Requirements Service Agreement between Baltimore Gas and Electric Company and Allegheny Energy Supply Company, L.L.C. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)

• 10(m) - Consent to Assignment and Assumption Agreement by and among Allegheny Energy Supply, L.L.C. and Baltimore Gas and Electric Company and Constellation Power Source, Inc. (Designated as Exhibit 10(l) to the Quarterly Report on Form lO-Q for the quarter ended June 30, 2003, File Nos. 1-12869 and 1-1910.) (Portions of this exhibit have been omitted pursuant to a request for confidential treatment.)

-10(n) - Constellation Energy Group, Inc. Benefits Restoration Plan, as amended and restated. (Designated as Exhibit No. 10(m) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)

"10(o) - Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated. (Designated as Exhibit No. 10(d) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)

130

"10(p) - Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated.

(Designated as Exhibit No. 10(e) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)

• 10(q) - Constellation Energy Group, Inc. Supplemental Benefits Plan, as amended and restated. (Designated as Exhibit No. 10(p) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.)

10(r) - Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and Michael J. Wallace.

10(s) - Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and Thomas E Brady.

10(t) - Constellation Energy Group, Inc. Executive Long-Term Incentive Plan, as amended and restated.

• 10(u) - Constellation Energy Group, Inc. 2002 Executive Annual Incentive Plan, as amended and restated.

(Designated as Exhibit 10(h) to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File Nos. 1-12869 and 1-1910.)

10(v) - Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan, as amended and restated.

10(w) - Constellation Energy Group, Inc. Management Long-Term Incentive Plan, as amended and restated.

• 10(x) - Summary of Constellation Energy Group, Inc. Board of Directors Non-Employee Director Compensation Program. (Designated as Exhibit 10(x) to the Annual Report on Form 10-K for the year ended December 31, 2004, File Nos. 1-12869 and 1-1910.)

10(y) - Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and E. Follin Smith.

'10(z) - Letter agreement, dated December 18, 2005, between Constellation Energy Group, Inc. and Mayo A.

Shattuck III. (Designated as Exhibit 10.1 to the Current Report on Form 8-K dated December 19, 2005, File Nos. 1-12869 and 1-1910.)

'10(aa) - 2006 Long-Term Incentive Program Guidelines. (Designated as Exhibit 10 to the Current Report on Form 8-K dated February 28, 2006, File No. 1-12869.)

10(bb) - Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and John R. Collins.

10(cc) - Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and Marc L. Ugol.

10(dd) - Amended and restated change in control severance agreement between Constellation Energy Group, Inc.

and Irving B. Yoskowitz.

12(a) - Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges.

12(b) - Baltimore Gas and Electric Company and Subsidiaries Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Eamings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.

21 - Subsidiaries of the Registrant.

23 - Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.

31(a) - Certification of Chairman of the Board, Chief Executive Officer and President of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(b) - Certification of Executive Vice President, Chief Financial Officer and Chief Administrative Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31 (c) - Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(d) - Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxlcy Act of 2002.

131

32(a) - Certification of Chairman of the Board, Chief Executive Officer and President of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32(b) - Certification of Executive Vice President and Chief Financial Officer of Constellation Energy Group, Inc.

pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32(c) - Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32(d) - Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Incorporated by Reference.

132

CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES AND BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE Il--VALUATION AND QUALIFYING ACCOUNTS Column A Column B Column C Column D Column E Additions Balance Charged Charged to at to costs Other Balance at beginning and Accounts- (Deductions)- end of Description of perio expenses Describe Describe period (In millions)

Reserves deducted in the Balance Sheet from the assets to which they apply:

Constellation Energy Accumulated Provision for Uncollectibles 2005 $ 43.1 $30.9 $ (26.6)(A) $ 47.4 2004 51.7 22.2 (30.8)(A) 43.1 2003 41.9 22.0 (12.2)(A) 51.7 Valuation Allowance Net unrealized loss on available for sale securities 2005 0.1 - 0.5 (B) -0.6 2004 - - 0.1 (B) -- 0.1 2003 Net unrealized (gain) loss on nuclear decommissioning trust funds 2005 (73.3) (37.0)(B) (110.3) 2004 (13.7) (59.6)(B) (73.3) 2003 47.4 (6 1.1) (B) (13.7)

BGE Accumulated Provision for Uncollectibles 2005 13.0 14.1 - (14.1)(A) 13.0 2004 10.7 16.3 - (14.0)(A) 13.0 2003 11.5 9.0 - (9.8)(A) 10.7 (A) Represents principally net amounts charged off as uncollectible.

(B) Represents amounts recorded in or reclassified from accumulated other comprehensive income.

133

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Constellation Energy Group, Inc., the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

CONSTELLATION ENERGY GROUP, INC.

(REGISTRANT)

Date: March 2, 2006 By Is/ MAYO A. SHATTUCK III Mayo A. Shattuck III Chairmanof the Board, Chief Executive Officer andPresident Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Constellation Energy Group, Inc., the Registrant, and in the capacities and on the dates indicated.

Signature Tide Date Principal executive officer and director:

By IsI M. A. Shattuck III Chairman of the Board, Chief March 2, 2006 M. A. Shattuck III Executive Officer, President and Director Principal financial and accounting officer:

By Isl E. E Smith Executive Vice President, Chief March 2, 2006 E. F. Smith Financial Officer, and Chief Administrative Officer Directors:

Is/ Y. C. de Balmann Director March 2, 2006 Y. C. de Balmann Is/ D. L. Becker Director March 2, 2006 D. L Becker Is/ J.T. Brady Director March 2, 2006 J. T. Brady

/s/ E P. Bramble, Sr. Director March 2, 2006 F. P. Bramble, Sr.

Is/ E. A. Crooke Director March 2. 2006 E. A. Crooke Is/ J. R. Curtiss Director March 2, 2006 J. R. Curtiss 134

Signature Title Date

/s/ F. A. Hrabowski, III Director March 2, 2006 F. A. Hrabowski, III Is/ N. Lampton Director March 2, 2006 N. Lampton Isf R. J. Lawless Director March 2, 2006 R. J. Lawless Is/ L. M. Martin Director March 2, 2006 L M. Martin' Is/ M. D. Sullivan Director March 2, 2006 M. D. Sullivan 135

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

BALTIMORE GAS AND ELECTRIC COMPANY (REGISTRANT)

Date: March 2, 2006 By Isl KENNETH W. DEFONTES, JR.

Kenneth W. DeFontes, Jr.

Presidentand ChiefExecutive Ofjfcer Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company, the Registrant, and in the capacities and on the dates indicated.

Signature Tide Date Principal executive officer and director:

By Is/ K. W. DeFontes, Jr. President, Chief Executive March 2, 2006 K. W. DeFontes, Jr. Officer, and Director Principal financial and accounting officer and director.

By Is/ E. E Smith Senior Vice President, Chief March 2, 2006 E. F. Smith Financial Officer, and Director Directors:

Is/ M. A. Shattuck III Director March 2, 2006 M. A. Shattuck III 136

Exhibit 31 (a)

CONSTELLATION ENERGY GROUP, INC.

CERTIFICATION I, Mayo A. Shattuck III, certify that:

l. I have reviewed this report on Form 10-K of Constellation Energy Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrants other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting.

Date: March 3, 2006 Isl MAYo A. SH'TrUCK III Chairman of the Board, President and Chief Executive Officer

Exhibit 31(b)

CONSTELLATION ENERGY GROUP, INC.

CERTIFICATION 1, E. Follin Smith, certify that:

1. I have reviewed this report on Form 10-K of Constellation Energy Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and

5. The registrants other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 3, 2006 Is! E. FOLUIN SMITH Executive Vice President, Chief Financial Officer and Chief Administrative Officer

Exhibit 31 (c)

BALTIMORE GAS AND ELECTRIC COMPANY CERTIFICATION 1, Kenneth W. DeFontes, Jr., certify that:

1. I have reviewed this report on Form 10-K of Baltimore Gas and Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 3, 2006 Isl KENNETH W. DEFONTES, JR.

President and Chief Executive Officer

Exhibit 31(d)

BALTIMORE GAS AND ELECTRIC COMPANY CERTIFICATION I, E. Follin Smith, certify that:

1. I have reviewed this report on Form 10-K of Baltimore Gas and Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrants other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 3, 2006 Isl E. FOLLIN SMmI.

Senior Vice President and Chief Financial Officer

Exhibit 32(a)

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 1, Mayo A. Shattuck III, Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc., certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:

(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2005 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Constellation Energy Group, Inc.

Isl MAYo A. SHATrUCK III Mayo A. Shattuck III Chairman of the Board, President and Chief Executive Officer Date: March 3, 2006

Exhibit 32(b)

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 1, E. Follin Smith, Executive Vice President, Chief Financial Officer, and Chief Administrative Officer of Constellation Energy Group, Inc., certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:

(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2005 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Constellation Energy Group, Inc.

Is/ E. FOLLIN SMITH E. Follin Smith Executive Vice President, Chief Financial Officer and Chief Administrative Officer Date: March 3, 2006

Exhibit 32(c)

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 I, Kenneth W. DeFontes, Jr., President and Chief Executive Officer of Baltimore Gas and Electric Company, certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:

(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2005 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gas and Electric Company.

Is/ KENNETH W. DEFONTES, JR.

Kenneth W. DeFontes, Jr.

President and Chief Executive Officer Date: March 3, 2006

Exhibit 32(d)

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 I, E. Follin Smith, Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company, certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:

(i) The accompanying Annual Report on Form 10-K for the year ended December 31, 2005 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gas and Electric Company.

Is/ E. FOLUN SMrmh E. Follin Smith Senior Vice President and Chief Financial Officer Date: March 3, 2006

ATTACHMENT (2)

Long Island Power Authority Basic Financial Statements Nine Mile Point Nuclear Station, LLC June 2, 2006

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Basic Financial Statements December 31, 2005 and 2004 (With Independent Auditors' Report Thereon)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Basic Financial Statements Table of Contents Page Section 1 Independent Auditors' Report I Management's Discussion and Analysis 3 Basic Financial Statements:

Balance Sheets 13 Statements of Revenues, Expenses, and Changes in Net Assets 15 Statements of Cash flows 16 Notes to Basic Financial Statements 17 Section 2 Report on Internal Control over Financial Reporting and on Compliance and other matters Based on an Audit of Financial Statements Performed in Accordance with GovernmentAuditing Standards 58

ffl,MKPMGT LLP Suite 200 1305 Wait Whitman Road Melville. NY 11747-4302 Independent Auditors' Report The Board of Trustees Long Island Power Authority:

We have audited the balance sheets, statements of revenues, expenses, and changes in net assets, and statements of cash flows of the Long Island Power Authority (Authority), a component unit of the State of New York, as of and for the years then ended December 31, 2005 and 2004, which collectively comprise the Authority's basic financial statements. These financial statements are the responsibility of the Authority's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Authority's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Authority as of December 31, 2005 and 2004, and the changes in its financial position and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

In accordance with Government Auditing Standards,we have also issued a report dated March 23, 2006 on our consideration of the Authority's internal control over financial reporting and on our tests of its compliance with certain provisions of laws, regulations, contracts, and grant agreements and other matters.

The purpose of that report is to describe the scope and of our testing of internal control over financial reporting and compliance and the results of that testing, and not to provide an opinion on the internal control over financial reporting or on compliance. That report is an integral part of an audit performed in accordance with Government Auditing Standards and should be considered in assessing the results of our audit.

KPMGUP..aU.S.k~itd lablity p.wlnmhp.

Is I, U.S.

ofKPMGkfentoe.i.l aSwincoovprn.tte meniw Trnm

The accompanying management's discussion and analysis on pages 3 through 12 is not a required part of the basic financial statements but is supplementary information required by U.S. generally accepted accounting principles. We have applied certain limited procedures, which consisted principally of inquiries of management regarding the methods of measurement and presentation of the required supplementary information. However, we did not audit the information and express no opinion on it.

LL-P March 23, 2006 2

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Management's Discussion and Analysis Years ended December 31,2005 and 2004 Overview of the Financial Statements This report consists of three parts: management's discussion and analysis, the basic financial statements, and the notes to the financial statements.

The financial statements provide summary information about the Authority's overall financial condition. The notes provide explanation and more details about the contents of the financial statements.

The Authority is considered a special-purpose government engaged in business-type activities and follows financial reporting for enterprise funds. The Authority's financial statements are prepared in accordance with generally accepted accounting principles (GAAP) as prescribed by the Governmental Accounting Standards Board (GASB). In accordance with GASB standards, the Authority has elected to comply with all authoritative pronouncements applicable to nongovernmental entities (i.e. pronouncements of the Financial Accounting Standards Board) that do not conflict with GASB pronouncements.

3 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Management's Discussion and Analysis Years ended December 31, 2005 and 2004 The following is a summary of the Authority's financial information for 2005, 2004, and 2003 (thousands of dollars):

Balance Sheet Summary December 31 2005 2004 2003 Assets:

Current assets:

Cash, cash equivalents and investments $ 470,880 412,968 417,987 Other current assets 501,018 369,636 328,929 Noncurrent assets:

Utility plant, net 4,004,646 3,540,103 3,390,387 Promissory notes receivable 155,425 155,425 155,425 Nonutility property and other investments 464,334 120,213 72,192 Deferred charges 173,828 180,149 120,102 Regulatory assets 859,513 900,032 957,540 Acquisition adjustment, net 3,079,939 3,192,620 3,305,300 Total assets $ 9,709,583 8,871,146 8,747,862 Liabilities and net assets:

Current liabilities $ 1,100,126 765,504 802,228 Noncurrent liabilities:

Long-term debt 6,686,136 6,865,277 6,835,943 Capital lease obligation 1,097,055 772,800 721,630 Other noncurrent liabilities 774,646 435,945 376,441 Total liabilities 9,657,963 8,839,526 8,736,242 Net assets (deficit): (475,991) (634,292) (566,082)

Capital assets net of related debt Unrestricted 527,611 665,912 577,702 Total net assets (deficit) 51,620 31,620 11,620 Total liabilities and net assets $ 9,709,583 8,871,146 8,747,862 4 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Management's Discussion and Analysis Years ended December 31, 2005 and 2004 Summary of Revenues, Expenses, and Changes in Net Assets Year ended December 31 2005 2004 2003 Electric revenue $ 3,281,186 2,853,837 2,583,603 Operating expenses:

Operations - fuel and purchased power 1,758,533 1,386,907 1,076,969 Operations and maintenance 723,774 691,937 733,655 General and administrative 43,567 40,962 44,875 Depreciation and amortization 237,863 229,316 230,085 Payments in lieu of taxes 222,609 215,312 213,382 Total operating expenses 2,986,346 2,564,434 2,298,966 Operating income 294,840 289,403 284,637 Other income, net 57,518 47,248 53,988 Interest charges (332,358) (316,651) (318,625)

Change in net assets before cumulative effect of change in accounting principle 20,000 20,000 20,000 Cumulative effect of change in accounting principle 2,873 Change in net assets 20,000 20,000 22,873 Net assets (deficit) - beginning of year 31,620 11,620 (11,253)

Net assets - end of year $ 51,620 31,620 11,620 Excess of Revenues over Expenses The revenues in excess of expenses for the twelve months ended December 31, 2005, 2004, and 2003 were

$20 million.

Revenue Revenue for the twelve months ended December 31, 2005, increased approximately $427 million. The increase is attributable to higher recoveries of excess fuel costs totaling approximately $378 million, the positive effects of weather, load growth and sales mix totaling approximately $49 million, and higher other miscellaneous revenue of approximately $5 million primarily due to service fees initiated during 2005. These increases were partially offset by the impact of having one less day of sales in 2005 as 2004 was a leap year, estimated to be approximately $5 million.

5 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Management's Discussion and Analysis Years ended December 31, 2005 and 2004 Revenue for the year ended December 31, 2004, increased approximately $270 million when compared to the similar period in 2003. The increase is attributable to higher recoveries of excess fuel costs totaling approximately $239 million, the positive effects of weather, load growth and sales mix totaling approximately

$25 million and the impact of the August 2003 blackout which caused a revenue loss in 2003 estimated at

$7 million. These positive impacts were partially offset by lower nonsystem revenue of approximately

$1 million.

Fuel and Purchased Power Costs LIPA's tariff includes a fuel recovery provision-the Fuel and Purchased Power Cost Adjustment ("FPPCA").

The FPPCA was modified by the Board in 2003 to allow LIPA to recover in the period incurred fuel and purchased power costs beyond those included in base rates ("Excess Fuel Costs"). As a result of this modification, the FPPCA is designed to recover a sufficient amount of fuel and purchased power costs to allow the Authority to earn $20 million of excess revenue over expenses each year as a reserve. If fuel prices change such that LIPA would exceed or fail to meet that financial target, the FPPCA will be reduced or increased accordingly. As a result of continuing increases in fuel and purchased power costs, the Authority increased the FPPCA in 2004 by an annual rate of 4.5% of base revenues in February, and by an additional annual rate of 5.0%

and 1.0% in June and October, respectively. In 2005, the Authority increased the FPPCA by 1.9% annually, effective June 8, and an additional 5.5% annually, effective October 8, as a result of the increasing fuel and purchased power costs. In December 2005, the Authority proposed to its Board a modified FPPCA to allow the Authority to earn $75 million of excess revenue over expenses each year with a variance of $50 million above or below such amount in each year. The proposed modification to the 2006 FPPCA was subject to a public hearing held in March 2006 and must be approved by the Board following such hearing prior to becoming effective. Also in connection with the adoption of the 2006 Operating Budget in December 2005, the Authority decreased the FPPCA by 1% effective January 1, 2006.

Fuel and purchased power costs for the twelve months ended December 31, 2005, increased approximately

$371 million as compared to the same period in 2004. This increase is primarily attributable to increased commodity costs totaling $330 million and higher sales volumes totaling approximately $24 million. Also the Authority partially offset fuel and purchased power costs by applying customer credits totaling $20 million whereas in the similar period of 2004, customer credits totaled $36 million.

Fuel and purchased power costs for the twelve months ended December 31, 2004 increased approximately $310 million as compared to the same period in 2003. However, due to the accounting mechanism of the FPPCA, prior year recoveries and deferrals comprise approximately $216 million of this variation. After eliminating these mechanisms, the increase is attributable to commodity costs totaling approximately $88 million and higher sales volumes totaling approximately $6 million.

Operations and Maintenance Expense (O&M)

O&M increased approximately $32 million for the twelve month period ended December 31, 2005, compared to the similar period in 2004 due to higher PSA costs totaling approximately $21 million (due primarily to agreed upon increased capacity charges totaling $14 million and the 2004 Utility Plant true-up totaling approximately

$4 million), higher storm reserve accruals totaling approximately $7 million, higher MSA costs totaling approximately $7 million, higher bad debt expense of approximately $5 million, higher clean energy expenses totaling approximately $4 million, and various other items totaling approximately $2 million.

6 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Management's Discussion and Analysis Years ended December 31, 2005 and 2004 These increases were partially offset by the absence in 2005 of any costs associated with renting temporary emergency stand-by generators whereas in 2004 LIPA incurred approximately $14 million.

O&M decreased approximately $42 million for the year ended December 31, 2004, compared to the similar period in 2003 primarily due to lower MSA costs totaling approximately $19 million, lower clean energy expenses totaling approximately $9 million, one-time recognition in 2003, of LIPA's $5 million contribution to the Shoreham bill credits as required by the Shoreham Property Tax Settlement Agreement (LIPA had no such funding in 2004), lower storm cost reserve accruals totaling approximately $12 million and lower costs associated with renting temporary emergency stand-by generators totaling approximately $1 million. Partially offsetting these decreases was increased customer accounts expenses of approximately $2 million, and $2 million related to the settlement of the Cross Sound Cable dispute.

General and Administrative Expenses (G&A)

General and administrative expenses increased for the year ended December 31, 2005 approximately $3 million due to the costs associated with the strategic assessment to evaluate LIPA's long-term organizational and business options, other various consulting costs and increased salary and benefit expenses.

General and administrative expenses decreased for the year ended December 31, 2004, approximately $4 million due primarily to decreased consulting costs related to forensic auditing services of approximately $3 million. The remaining decrease is due to lower insurance costs totaling approximately $1 million.

Depreciation and Amortization For the year ended December 31, 2005, depreciation and amortization increased approximately $9 million due to higher utility plant balances in 2005 when compared to 2004.

For the year ended December 31, 2004, depreciation and amortization decreased approximately $1 million.

During 2003, an adjustment totaling approximately $6 million was recognized in conjunction with the adoption of the accounting for asset retirement obligations. Partially offsetting that decrease of $6 million is higher utility plant balances in 2004 when compared to 2003 resulting in approximately $5 million higher depreciation expense.

Payments in Lieu of Taxes For the year ended December 31, 2005, payments in lieu of taxes (PILOTs) increased approximately $7 million due to increased property and school taxes.

For the year ended December 31, 2004, PILOTs increased approximately $2 million due to increased property taxes totaling approximately $6 million. This increase was partially offset by decreased revenue taxes (due to lower tax rates) totaling approximately $4 million.

7 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Management's Discussion and Analysis Years ended December 31, 2005 and 2004 Other Income, Net For the year ended December 31, 2005, other income increased approximately $10 million due to higher earnings on investment balances which includes amounts held as collateral from various counterparties, totaling approximately $9 million and higher sales of emissions credits totaling approximately $6 million. These increases were partially offset by lower interest income related to New York Independent System Operator (NYISO) prior month's re-bills totaling approximately $5 million.

For the year ended December 31, 2004, other income decreased approximately $7 million. This decrease was the result of lower investment income of approximately $2 million due to lower investment balances, and lower emissions credit income totaling approximately $9 million. These decreases were partially offset by interest received on New York Independent System Operator (NYISO) prior months' re-bills totaling approximately

$3 million and higher carrying charges of approximately $1 million on the Shoreham property tax settlement regulatory asset.

Interest Charges and Credits For the year ended December 31, 2005, interest charges and credits increased approximately $16 million due to increased interest expense on long term debt due primarily to higher interest rates on variable rate debt combined with slightly higher average debt balances outstanding in 2005 when compared to 2004. Additionally during 2005, the Authority incurred interest expense on amounts held as collateral from various counterparties which is offset with increased "other income" earned on amounts held as collateral.

For the year ended December 31, 2004, interest charges and credits decreased approximately $2 million resulting from lower carrying charge expenses on deferred credits and lower deferred loss amortizations totaling approximately $7 million. This decrease was partially offset by higher interest on long term debt totaling approximately $3 million, due to higher average debt outstanding, and further offset by lower credits from allowance for borrowed funds used during construction (AFC) of approximately $2 million, due to lower construction work in progress balances in 2004 compared to 2003.

Cash, Cash Equivalents, and Investments The Authority's cash, cash equivalents, and investments totaled approximately $471 million, $413 million, and

$418 million at December 31, 2005, 2004, and 2003, respectively. The increase from 2004 to 2005 is primarily the result of counterparty collateral held by LIPA. The decrease from 2003 to 2004 is primarily the result of higher fuel and purchased power costs. The Authority has maintained a $250 million balance in its Rate Stabilization Fund. The Authority also has the ability to issue up to $200 million of commercial paper notes,

$100 million of which is outstanding as of December 31, 2005 and 2004.

8 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Management's Discussion and Analysis Years ended December 31, 2005 and 2004 Capital Assets During 2005 two new natural gas fired generating facilities were constructed on Long Island by separate entities, with a combined capacity of 160 MW. Each of these facilities began supplying capacity and energy to LIPA in accordance with the terms of the Power Purchase Agreements (PPA's) negotiated in 2004. Under the terms of these agreements, LIPA receives 100% of the output from the newly constructed generating unit for a term of 20 years. These PPAs qualify for capitalization under FASB Emerging Issues Task Force Issue No. 01-08 Determining Whether an Arrangement is a Lease and SFAS No. 13, Accounting for Leases, and have been included in both Utility Plant and Capital Lease Obligations.

During 2004 two generating facilities were constructed on Long Island by two separate entities with a combined capacity of approximately 96MW. Each of these facilities began supplying capacity and energy to LIPA in accordance with the terms of the PPA's negotiated in 2003. Under the terms of one of those agreements, LIPA receives 100% of the output from the facility for a term of 13 years. The agreement contains two optional renewal periods of five years each. This PPA qualifies for capitalization under FASB Emerging Issues Task Force Issue No. 01-08 Determining Whether an Arrangement is a Lease and SFAS No. 13, Accounting for Leases, and has been included in both Utility Plant and Capital Lease Obligations. The other PPA provides LIPA with 10MW of the capacity and energy for a period of 30 years. This PPA did not qualify for capitalization and is being reported as an executory contract.

Costs incurred under the PPAs are includible in fuel and purchased power costs in the period incurred, in accordance with the FPPCA provisions of the Authority Tariff for Electric Service.

For additional information on power purchase agreements, see footnote 11 of notes to basic financial statements.

The Authority also continued its program of strategic investment in transmission and distribution (T&D) upgrades to improve reliability and to enhance capacity needed to meet growing customer demands. For the years ended December 31, 2005 and 2004, T&D capital improvements totaled $215 million and $204 million, respectively. These improvements included the replacement or upgrade of transformer banks and circuit breakers, new substations, enhanced transmission lines and upgraded command and control equipment.

Regulatory Assets Regulatory assets decreased approximately $41 million from December 31, 2004 to December 31, 2005. The decrease is the result of (i) the scheduled recovery of approximately $37 million, representing a portion of the 2003 deferred Excess Fuel Costs scheduled to be recovered over a ten-year period which began January 1, 2004, in accordance with LIPA's tariff (ii) the scheduled recovery of approximately $36 million related to the Shoreham Property Tax Settlement Agreement through a surcharge on billings for electric service to customers residing in Suffolk County (the Shoreham surcharge), which began in June 2003 (as discussed in greater detail in note 3 of notes to basic financial statements); (iii) partially offset by the additional carrying charges on the Shoreham Property Tax Settlement Agreement related credits totaling approximately $32 million.

9 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Management's Discussion and Analysis Years ended December 31, 2005 and 2004 Regulatory assets decreased approximately $57 million from December 31, 2003 to December 31, 2004. The decrease is the result of (i) the scheduled recovery of a portion of the 2003 deferred Excess Fuel Costs totaling approximately $36 million, (ii) the decrease in the deferred unrealized losses on LIPA's fuel hedges totaling approximately $17 million and (iii) the scheduled recovery of approximately $35 million related to the Shoreham Property Tax Settlement; partially offset by the additional carrying charges on the Shoreham Property Tax Settlement Agreement related credits totaling approximately $31 million.

Debt The Authority's long-term debt, including current maturities is comprised of the following instruments:

Debt (Thousands of dollars)

Balance at December 31 2005 2004 2003 General Revenue Bonds $ 5,826,115 5,966,549 5,900,544 Subordinated Revenue Bonds 935,045 962,345 989,645 Commercial Paper Notes 100,000 100,000 100,000 NYSERDA Notes 155,420 155,420 155,420

$ 7,016,580 7,184,314 7,145,609 During 2005, debt decreased as a result of the scheduled maturities of approximately $194 million, partially offset by the accretion of the capital appreciation bonds totaling $26 million.

During 2004, the Authority issued $200 million Electric System General Revenue Bonds, Series 2004A. The issuance consisted of $33.9 million of Serial bonds and $166.1 million of Term bonds. The Serial bonds have maturities that begin in 2013 and continue each year through 2025. Interest rates on the Serial bonds range from 3.8% to 4.875%. The Term bonds have maturities of $64.9 million in 2029, $12.4 million in 2032, and

$88.8 million in 2034. Interest rates on the Term bonds are 5.0% and 5.1%. The purpose of these bonds was to reimburse LIPA's treasury for capital projects funded previously with cash from operations, and to provide funding for future capital spending.

In addition, debt decreased as a result of the scheduled maturities of approximately $186 million, partially offset by the accretion of the capital appreciation bonds totaling $25 million.

10 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Management's Discussion and Analysis Years ended December 31, 2005 and 2004 Investment Ratings Below are the Authority's securities as rated by Standard and Poor's Corporation (S&P), Moody's Investors Service (Moody's), and Fitch Investors Services, LP (Fitch):

Investment ratings Standard Moody's & Poors Fitch Senior Lien Debt A3 A- A-Certain Senior and all Subordinated Lien debt and the Commercial Paper notes are supported by either a Letter of Credit (LOC) or are insured. Such debt carries the ratings of the LOC syndicate or insurance company, not that of the Authority.

Risk Management The Authority is routinely exposed to commodity and interest rate risk. In order to mitigate such exposure, the Authority formed an Executive Risk Management Committee to strengthen executive management oversight for the risk mitigation activities of the Authority. In addition, the Authority retains an external consultant specializing in risk management, energy markets and energy trading to enhance its understanding of these areas.

Whenever the Authority enters into a transaction to mitigate risk, it becomes exposed to an event of nonperformance by the counterparty. To limit its exposure to such risk, the Authority will only enter into derivative transactions with counterparties that have a credit rating of "investment grade" or better. For commodity derivatives the Authority requires collateral for mark to market values above an established credit limit set for each counterparty. At December 31, 2005, the Authority held approximately $232 million of counterparty collateral, included in current liabilities. At December 31, 2004, no such amounts were required to be posted by the Authority's counterparties.

The goal of the Authority's risk management program is to reduce the impact that energy price volatility and interest rate fluctuations could have on rates if not mitigated with derivative products.

Fuel and purchasedpower transactions: - The Authority, uses derivative financial instruments to protect its customers from market price fluctuations for the purchase of fuel oil, natural gas, and electricity. These instruments are recorded at their market value. Any unrealized gains and losses are deferred until realized, in accordance with the modifications to the FPPCA. Upon realization, such gains and losses will be reflected in income and considered in the determination of the FPPCA. At December 31, 2005 and 2004, the Authority had unrealized gains on commodity derivatives of approximately $369 million and $24 million, respectively, based on quoted market prices.

I1I (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Management's Discussion and Analysis Years ended December 31, 2005 and 2004 Interest rate transactions:- During 2004, the Authority entered into a basis swap with three counterparties for a notional amount of approximately $1 billion under terms that require LIPA to pay the counterparties the Bond Market Association (BMA) Index in exchange for a fixed percent of LIBOR. This agreement became effective July 1, 2004, and continues through August 15, 2033. Under the terms of the agreement, LIPA received, on June 28, 2004, an up front premium of $35 million which is being amortized as an interest rate modifier over the life of the agreement.

During 2004, the Authority also entered into two fixed-to-floating rate swap agreements, each with a notional amount of approximately $101 million. Under the terms of these identical agreements, LIPA pays a floating rate equal to the BMA index, and receives a fixed rate of interest. The agreements became effective July 1, 2004, and are co-terminus with the underlying securities, the last of which matures September 1, 2016. These agreements are cancelable by the counterparties on July 1, 2007.

In accordance with SFAS No. 133, Accounting for Derivatives and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, and SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, the Authority marks its financial derivatives to market and records unrealized gains and losses. At December 31, 2005 and 2004, the Authority had as unrealized market value loss of approximately $218 million. The Authority received approximately $125 million of upfront premiums related to those transactions which are being amortized as interest rate modifiers. The gains and losses resulting from these market values have been deferred, and will be recognized when realized.

Other Power Supply The Authority has entered into numerous agreements for capacity and energy necessary to continue to satisfy the increasing energy demand of Long Island, while increasing the diversity of its fuel mix alternatives. During 2005, the Authority began to receive 100% of the output from two newly constructed facilities with total combined capacity of approximately 160MW, which became commercially operational just prior to the summer of 2005. In addition, the construction and installation of a submarine cable to connect Long Island to the power supplies of the PJM Interconnection has progressed on schedule to be commercially operational by the summer of 2007, and the vendor with whom LIPA has engaged to construct and operate a 350MW (LIPA's allocation is approximately 300MW) combined cycle gas fired facility on Long Island, to be commercially operational by the summer of 2009, are in the permitting and engineering phase of the project. LIPA also entered into an agreement for a 140MW off-shore wind farm with a targeted commercial operation date of 2008.

Contacting the Long Island Power Authority This financial report is designed to provide our bondholders, customers, and other interested parties with a general overview of the Authority's finances and to demonstrate its accountability for the funds it receives. If you have any questions about this report or need additional information, contact the Authority at 333 Earle Ovington Blvd., Suite 403, Uniondale, New York 11553, or visit our website at www.lipower.org.

12

LONG ISLAND POWER AUTHORITY (A Component Unit of the State of New York)

Balance Sheets December 31, 2005 and 2004 (Dollars in thousands)

Assets 2005 2004 Current assets:

Cash and cash equivalents $ 454,414 335,068 Investments 16,466 77,900 Accounts receivable (net of allowance for doubtful accounts of $19,485 and $19,635, respectively) 343,673 274,184 Other accounts receivable 23,902 11,344 Fuel inventory 104,652 66,948 Material and supplies inventory 7,365 7,128 Interest receivable 153 300 Prepayments and other current assets 21,273 9,732 Total current assets 971,898 782,604 Noncurrent assets:

Utility plant and property and equipment, net 4,004,646 3,540,103 Promissory notes receivable - KeySpan Energy 155,425 155,425 Nonutility property and other investments 464,334 120,213 Deferred loss related to nonfuel derivatives 88,778 86,177 Deferred charges 85,050 93,972 Regulatory assets:

Shoreham property tax settlement 568,316 572,101 Fuel and purchased power costs recoverable 291,197 327,931 Total regulatory assets 859,513 900,032 Acquisition adjustment (net of accumulated amortization of $1,015,572 and $902,891, respectively) 3,079,939 3,192,620 Total assets $ 9,709,583 8,871,146 See accompanying notes to basic financial statements.

13

Liabilities and Net Assets 2005 2004 Current liabilities:

Short-term debt $ 100,000 100,000 Current maturities of long-term debt 202,325 193,630 Current portion of capital lease obligation 121,813 89,552 Accounts payable and accrued expenses 332,008 275,054 Accrued payments in lieu of taxes 43,552 38,082 Accrued interest 44,780 44,465 Counterparty collateral 232,424 Customer deposits 23,224 24,721 Total current liabilities 1,100,126 765,504 Noncurrent liabilities:

Long-term debt 6,686,136 6,865,277 Capital lease obligation 1,097,055 772,800 Asset retirement obligation 81,463 68,320 Deferred credits 68,601 85,323 Deferred credits - financial derivatives 222,996 228,126 Deferred gain - financial derivatives 6,339 10,410 Regulatory liability - fuel derivatives 368,666 23,675 Claims and damages 26,581 20,091 Commitments and contingencies (note 11)

Total noncurrent liabilities 8,557,837 8,074,022 Net assets (deficit):

Invested in capital assets net of related debt (475,991) (634,292)

Unrestricted 527,611 665,912 Total net assets 51,620 31,620 Total liabilities and net assets $ 9,709,583 8,871,146 14

LONG ISLAND POWER AUTHORITY (A Component Unit of the State of New York)

Statements of Revenues, Expenses, and Changes in Net Assets Years ended December 31, 2005 and 2004 (Dollars in thousands) 2005 2004 Operating revenues - electric sales $ 3,281,186 2,853,837 Operating expenses:

Operations - fuel and purchased power 1,758,533 1,386,907 Operations and maintenance 723,774 691,937 General and administrative 43,567 40,962 Depreciation and amortization 237,863 229,316 Payments in lieu of taxes 222,609 215,312 Total operating expenses 2,986,346 2,564,434 Operating income 294,840 289,403 Nonoperating revenues and expenses:

Other income, net:

Investing income 17,886 7,362 Carrying charges on regulatory asset 32,345 31,577 Other 7,287 8,309 Total other income, net 57,518 47,248 Interest charges and (credits):

Interest on long-term debt, net 311,391 298,764 Other interest 23,398 20,110 Allowance for borrowed funds used during construction (2,431) (2,223)

Total interest charges 332,358 316,651 Total nonoperating revenues and expenses (274,840) (269,403)

Change in net assets 20,000 20,000 Total net assets, beginning of year 31,620 11,620 Total net assets, end of year $ 51,620 31,620 See accompanying notes to basic financial statements.

15

LONG ISLAND POWER AUTHORITY (A Component Unit of the State of New York)

Statements of Cash Flows Years ended December 31,2005 and 2004 (Dollars in thousands) 2005 2004 Cash flows from operating activities:

Received from customers for the system sales, net of refunds $ 3,273,787 2,896,658 Other operating revenues received 26,979 28,750 Paid to suppliers and employees:

Operations and maintenance (745,937) (781,617)

Fuel and purchased power (1,704,529) (1,398,626)

Payments in lieu of taxes (314,511) (304,004)

Margin calls on fuel derivative transactions, net 232,424 Net cash provided by operating activities 768,213 441,161 Investing activities:

Net sales (purchases) of investment securities 61,434 120,992 Earnings received on investments 17,703 5,773 Other 2,545 3,371 Net cash provided by investing activities 81,682 130,136 Cash flows from capital and related financing activities:

Capital and nuclear fuel expenditures (229,691) (208,431)

Swaption proceeds 35,000 Proceeds from the issuance of bonds, net of issuance costs (307,228) 192,806 Interest paid, net (288,319)

Redemption of long-term debt (193,630) (186,380)

Net cash used in capital and related financing activities (730,549) (455,324)

Net increase in cash and cash equivalents 119,346 115,973 Cash and cash equivalents at beginning of period 335,068 219,095 Cash and cash equivalents at end of period $ 454,414 335,068 Reconciliation to net cash provided by operating activities:

Operating income $ 294,840 289,403 Adjustments to reconcile excess of operating income to net cash provided by operating activities:

Depreciation and amortization 237,863 229,316 Nuclear fuel burned 5,806 4,951 Shoreham surcharges (credits), net 36,130 35,136 Provision for claims and damages 19,824 5,019 Accretion of asset retirement obligation 6,295 3,868 Other, net (13,893) (41,995)

Changes in operating assets and liabilities:

Accounts receivable, net (81,897) (24,818)

Fuel and material and supplies inventory (37,941) (12,295)

Fuel and purchased power costs recovered related to prior periods 37,034 36,085 Counterparty collateral 232,424 Accounts payable and accrued expenses 31,728 (83,509)

Net cash provided by operating activities $ 768,213 441,161 See accompanying notes to basic financial statements.

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LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 (1) Basis of Presentation The Long Island Power Authority (Authority) was established as a corporate municipal instrumentality of the State of New York, constituting a political subdivision of the State, created by Chapter 517 of the Laws of 1986 (the Act). As such, it is a component unit of the State and is included in the State's annual financial statements.

The Authority reporting entity is comprised of itself and its operating subsidiary the Long Island Lighting Company, a wholly owned subsidiary of the Authority doing business as LIPA. LIPA has 1 share of $1 par value common stock authorized, issued and outstanding, which is held by the Authority.

As the Authority holds 100% of the common stock of LIPA and substantially controls the operations of LIPA, under Government Accounting Standard Board Statement No. 14, The FinancialReporting Entity, LIPA is considered a blended component unit of the Authority and the assets, liabilities and results of operations are consolidated with the operation of the Authority for financial reporting purposes.

The Authority and its blended component unit, LIPA, are referred to collectively, as the "Company" in the financial statements. All significant transactions between the Authority and LIPA have been eliminated.

(2) Nature of Operations LIPA, as owner of the transmission and distribution system located in the New York State Counties of Nassau and Suffolk (with certain limited exceptions) and a small portion of Queens County known as the Rockaways (Service Area), is responsible for supplying electricity to customers within the service area. To assist LIPA in meeting these responsibilities, LIPA contracted with KeySpan Energy Corporation (KeySpan) or its affiliates to provide: operations and management services related to the transmission and distribution system through a management services agreement (MSA); capacity and energy from the fossil fired generating plants of KeySpan, formerly owned by LILCO, through a power supply agreement (PSA);

and, energy and fuel management services through an energy management agreement (EMA) (collectively; the Operating Agreements). Through these contracts, LIPA pays KeySpan directly for these services and KeySpan, in turn, pays the salaries of its employees and fees of its contractors and suppliers. In 2005 and 2004, LIPA paid to KeySpan approximately $1.7 billion each year under the operating agreements, which includes all fees under such agreements, reimbursement for various taxes and PILOTS, certain fuel and purchase power costs, capital projects, conservation services, research and development and various other expenditures authorized by the Company.

On February 27, 2006 KeySpan announced a definitive agreement under which KeySpan would be acquired in early 2007 by an affiliate of National Grid plc, a company organized under the laws of England and Wales. The transaction is subject to the approval of the shareholders of both companies and to various regulatory approvals. In the event there is a change of control of KeySpan, the Authority and LIPA would have the option of canceling their contracts with KeySpan and the KeySpan subsidiaries.

The Authority and LIPA are also parties to an Administrative Services Agreement, which describes the terms and conditions under which the Authority provides personnel, personnel-related services, and other services necessary for LIPA to provide service to its customers. As compensation to the Authority for the services described above, the Authority charges LIPA a monthly management fee equal to the costs incurred by the Authority in order to perform its obligations under the agreements described above.

17 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 (3) Summary of Significant Accounting Policies (a) General The Company complies with all applicable pronouncements of the Governmental Accounting Standards Board (GASB). In accordance with GASB Statement No. 20, Accounting and Financial Reporting for ProprietaryFunds and Other Governmental Entities That Use ProprietaryFund Accounting, the Company complies with all authoritative pronouncements applicable to nongovernmental entities (i.e., pronouncements of the Financial Accounting Standards Board) that do not conflict with GASB pronouncements.

The operations of the Company are presented as an enterprise fund following the accrual basis of accounting in order to recognize the flow of economic resources. Under this basis, revenues are recognized in the period which they are earned and expenses are recognized in the period in which they are incurred.

(b) Accountingfor the Effects of Rate Regulation The Company is subject to the provisions of Statement of Financial Accounting Standards (SFAS)

No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). This statement recognizes the economic ability of regulators, through the ratemaking process, to create future economic benefits and obligations affecting rate-regulated companies. Accordingly, the Company records these future economic benefits and obligations as regulatory assets and regulatory liabilities, respectively.

Regulatory assets represent probable future revenues associated with previously incurred costs that are expected to be recovered from customers. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be refunded to customers through the ratemaking process.

In order for a rate-regulated entity to continue to apply the provisions of SFAS No. 71, it must continue to meet the following three criteria: (1) the enterprise's rates for regulated services provided to its customers must be established by an independent third-party regulator or its own governing board empowered by a statute to establish rates that bind customers; (2) the regulated rates must be designed to recover the specific enterprise's costs of providing the regulated services; and (3) in view of the demand for the regulated services and the level of competition, it is reasonable to assume that rates set at levels that will recover the enterprise's costs can be charged to and collected from customers.

Based upon the Company's evaluation of the three criteria discussed above in relation to its operations, and the effect of competition on its ability to recover its costs, the Company believes that SFAS No. 71 continues to apply.

If the Company had been unable to continue to apply the provisions of SFAS No. 71, as of December 31, 2005, the Company estimates that approximately $291 million of fuel and purchased power and the acquisition adjustment, totaling approximately $3.1 billion would be considered for impairment.

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LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 (c) Utility Plantand Propertyand Equipment Additions to and replacements of utility plant are capitalized at original cost, which includes material, labor, indirect costs associated with an addition or replacement, plus an allowance for borrowed funds used during construction. The cost of renewals and betterments relating to units of property is added to utility plant. The cost of property replaced, retired or otherwise disposed of is deducted from utility plant and, generally, together with dismantling costs less any salvage, is charged to accumulated depreciation. The cost of repairs and minor renewals is charged to maintenance expense. Mass properties (such as poles, wire and meters) are accounted for on an average unit cost basis by year of installation.

Property and equipment represents leasehold improvements, office equipment and furniture and fixtures of the Authority.

(d) Cash and Cash Equivalents andInvestments Funds held by the Authority are administered in accordance with the Authority's investment guidelines pursuant to Section 2925 of the New York State Public Authorities Law. These guidelines comply with the New York State Comptroller's investment guidelines for public authorities. Certain investments and cash and cash equivalents have been designated by the Authority's Board of Trustees to be used for specific purposes, including rate stabilization, debt service, capital expenditures, and Clean Energy initiatives. Investments' carrying value is reported at amortized cost, which approximates fair market value.

The Authority adopted the provisions of GASB Statement No. 40, Deposit and Investment Risk Disclosures for the year ended December 31, 2005.

(e) Fuel Inventory Under the terms of the EMA and various Power Purchase Agreements, LIPA owns the fuel oil used in the generation of electricity at the facilities under contract to LIPA. Fuel inventory represents the value of low sulfur and internal combustion fuels that LIPA had on hand at each year-end in order to meet the demand requirements of these generating stations. Fuel inventory is valued using the weighted average cost method.

(C) MaterialandSupplies Inventory This represents LIPA's share of material and supplies inventory needed to support the operation of the Nine Mile Point 2 (NMP2) nuclear power station.

19 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 (g) PromissoryNote Receivable As part of the 1998 Merger, KeySpan issued promissory notes to LIPA of approximately

$1.048 billion. As of December31, 2005 and 2004, approximately $155 million remained outstanding, respectively. The interest rates and timing of principal and interest payments on the promissory notes from KeySpan are identical to the terms of certain LILCO indebtedness assumed by LIPA in the merger. KeySpan is required to make principal payments to LIPA thirty days prior to the corresponding payment due dates, and LIPA transfers those amounts to the debt holders in accordance with the original debt repayment schedule.

(h) Nonutility Propertyand Other Investments The Authority's nonutility property and other investments consist of: (i) the fair value of its derivatives totaling approximately $405 million and (ii) its investment in the Nine Mile Point 2 Decommissioning Trust Fund totaling approximately $59 million.

(i) DeferredLoss Related to Non-FuelDerivatives The Authority uses financial derivative instruments to manage the impact of interest rates on its customers, earnings and cash flows. Under the provisions of SFAS No. 133, Accounting for Derivatives and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and CertainHedgingActivities, and SFAS No. 149, Amendment of Statement 133 on DerivativeInstruments and HedgingActivities, the Authority is required to recognize the fair value of all derivative instruments as either an asset or liability on the balance sheet with an offsetting gain or loss recognized. These standards permit the deferral of hedge gains and losses to Other Comprehensive Income, under specific hedge accounting provisions, until the hedged transaction is realized. However, the Authority is a governmental agency and, therefore, its financial statements are prepared in accordance with the provisions of the Governmental Accounting Standards Board, which do not provide for Other Comprehensive Income.

As the Authority is subject to the provisions of SFAS No. 71, all such gains and losses are deferred until realized. Accordingly, the Authority's balance sheet reflects the inclusion of deferred losses and the deferred gains.

6F) Deferred Charges Deferred charges represent primarily the unamortized balance of costs incurred to issue long-term debt. Such amounts are amortized to interest expense over the life of the debt issuance to which they relate. Also included in deferred charges are amounts incurred by the Authority related to various energy projects, the amortization of which will be over the period of benefit (the life of the related Power Purchase Agreement).

20 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 (k) RegulatoryAssets Shoreham PropertyTax Settlement (Settlement)

In January 2000, the Authority reached an agreement with Suffolk County, Town of Brookhaven, Shoreham-Wading River Central School District, Wading River Fire District and Shoreham-Wading River Library District (which was succeeded by the North Shore Library District) (collectively, the Suffolk Taxing Jurisdictions) and Nassau County regarding the over assessment of the Shoreham Nuclear Power Station. As required under the terms of the agreement, the Authority was required to issue $457.5 million of rebates and credits to customers over the five-year period which began May 29, 1998. In order to fund such rebates and credits, the Authority used the proceeds from the issuance in May 1998 of its Capital Appreciation Bonds, Series 1998A Electric System General Revenue Bonds totaling approximately $146 million and the issuance in May 2000 of approximately

$325 million of Electric System General Revenue Bonds, Series 2000A.

As provided under the Agreement, beginning in June 2003, LIPA's Suffolk County customers' bills include a surcharge (the Suffolk Surcharge) to be collected over the succeeding approximate 25 year period to repay the Authority for debt service and issuance costs on the bonds issued by the Authority to fund the Settlement as well as its cost of pre-funding certain rebates and credits.

As future rates will be established at a level sufficient to recover all such costs identified above, LIPA recorded a regulatory asset in accordance with SFAS No. 71. The balance of the Shoreham property tax settlement regulatory asset as of December 31, 2005 and 2004 was approximately

$568.3 million and $572.1 million, respectively. The balance represents costs recorded from 1998 through 2004 including rebates and credits issued to customers, costs of administering the program and debt service costs on the Bonds identified above less surcharges collected since May 2003 totaling approximately $90 million.

Fuel andPurchasedPower Costs Recoverable LIPA's Tariff for Electric Service ("Tariff") includes a fuel recovery mechanism - the Fuel and Purchased Power Cost Adjustment (FPPCA) - whereby customer bills may be adjusted to reflect changes in the cost of fuel, purchased power and related costs. The FPPCA allows LIPA to recover from customers amounts incurred for fuel and purchased power beyond those included in base rates (Excess Fuel Costs).

Modification to the FPPCA Mechanism During 2003, the FPPCA was modified to allow LIPA to recover from customers amounts incurred for fuel and purchased power beyond those included in base rates ("Excess Fuel Costs") in the period incurred, as opposed to a deferral method. This modification was fully implemented on January 1, 2004. As of that date, the FPPCA was set so that LIPA would recover an amount of Excess Fuel Costs necessary to achieve revenue in excess of expenses of

$20 million annually as a reserve. In no event, however, would the FPPCA be set at a level that would recover more than LIPA's Excess Fuel Costs.

21 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 Effective with the Board's adoption of the 2004 budget in mid-February 2004, the FPPCA surcharge was increased by an annual rate of 4.5% and, as a result of the continuing increases in fuel and purchased power costs, the Authority increased the surcharge by an additional annual rate of 5.0% effective June 8, 2004 and by 1.0% effective October 1, 2004. In 2005, the Authority increased the FPPCA by 1.9% annually, effective June 8, and an additional 5.5%

annually, effective October 8, 2005. These increases were necessary to comply with the modified FPPCA mechanism, in effect during 2004 and 2005.

In December 2005, a modification to the 2006 FPPCA was proposed that would increase the reserve target noted above from $20 million annually to $75 million with a "tolerance band".

At the start of each calendar year, the FPPCA would be set at a level designed to achieve the targeted reserve of $75 million, with a tolerance band of $50 million above and $50 million below that level. During the year, the Authority would monitor, and if necessary modify, the FPPCA to achieve no less than $25 million and no more than $125 million of reserve. If the reserve is projected to fall below $25 million for the year, the FPPCA would be increased to a level sufficient to produce a reserve of $25 million to $75 million for the year (i.e., the lower half of the tolerance band). If the reserve is projected to exceed $125 million for the year, the FPPCA would be decreased to a level sufficient to produce $75 million to $125 million for the year (i.e., the upper half of the tolerance band). If the projected reserve for the year is between

$25 million and $125 million, the FPPCA would not change. The proposed modification to the FPPCA was subject to a public hearing held in March 2006 and must be approved by the Board following such hearing prior to becoming effective. Also in connection with the adoption of the 2006 Operating Budget in December 2005, the Authority decreased the FPPCA by 1% annually effective January 1, 2006.

To protect its customers from significant market price fluctuations for the purchase of fuel oil, natural gas, and electricity, LIPA uses derivative financial instruments which, are recorded at their market value. Effective with the 2003 modifications to the FPPCA, unrealized gains or losses derived from these derivatives are deferred as a regulatory asset until realized, at which time they are included in current period results as a component of fuel and purchased power.

Accordingly, as of December 31, 2005, the Authority deferred its unrealized gain on fuel derivatives of approximately $369 million.

(!) Acquisition Adjustment The acquisition adjustment represents the difference between the purchase price paid and the net assets acquired from LILCO and is being amortized and recovered through rates on a straight-line basis using a 35-year life.

(m) Fair Values of FinancialInstruments The Company's financial instruments approximate their fair market value as of December 31, 2005 and 2004. The fair values of the Company's long-term debt and derivative instruments are based on quoted market prices.

22 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 (n) CapitalizedLease Obligations Represents the net present value of various contracts for the capacity and/or energy of certain generation and transmission facilities in accordance with Emerging Issues Task Force No. 01-08, Determining if Whether an Arrangement Contains a Lease, and Statement of Financial Accounting Standards (SFAS) No. 13, Accountingfor Leases. Upon satisfying the capitalization criteria, the net present value of the contract payments is included in both Utility Plant and Capital Lease Obligations.

As of December 31, 2005, and 2004, the unamortized net present value of the minimum contract payments related to the various contracts totaled approximately $1.2 billion and $862 million, respectively.

As permitted under SFAS No. 71, LIPA recognizes in Fuel and Purchased Power expense an amount equal to the contract payment of the capitalized leases discussed above, as allowed through the ratemaking process. The value of the asset and the obligation are reduced each month so that the balance sheet properly reflects the remaining value of the asset and obligation at each month end.

For a further discussion on the capitalization of capacity and/or energy contracts, see note 11 of notes to basic financial statements.

(o) DeferredCredits Deferred credits represent amounts received by the Authority, the final disposition of which remains undetermined. Accordingly, the Authority has deferred the recognition of income until such determination is reached. Certain of these amounts may be returned to customers, KeySpan or the Internal Revenue Service.

During 2005 and 2004, amounts determined as due to customers totaling approximately $20 million and $36 million, respectively, were applied against the Excess Fuel Costs.

(p) Claims and Damages Losses arising from claims against LIPA, including workers' compensation claims, property damage, and general liability claims are partially self-insured. Storm losses are self-insured by LIPA.

Reserves for these claims and damages are based on, among other things, experience, and expected loss. In certain instances, significant portions of extraordinary storm losses may be recoverable from the Federal Emergency Management Agency.

(q) Revenues Operating revenues are comprised of cycle billings for electric service rendered to customers, based on meter reads, and the accrual of revenues for electric service rendered to customers not billed at month-end. All other revenue not meeting this definition is reported as nonoperating revenue when service is rendered. For the years ended December 31, 2005, and 2004, LIPA received approximately 52% of its revenues from residential sales, 44% from sales to commercial and industrial customers, and the balance from sales to public authorities and municipalities.

23 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 Cr) Depreciation The provisions for depreciation for utility plant result from the application of straight-line rates by groups of depreciable properties in service. The rates are determined by age-life studies performed on depreciable properties. The average composite depreciation rate is 2.99%.

Leasehold improvements are being amortized over the lesser of the life of the assets or the term of the lease, using the straight-line method. Property and equipment is being depreciated over its estimated useful life using the straight-line method.

The following estimated useful lives and capitalization thresholds are used for utility property:

Capitalization Category Useful life threshold Generation-nuclear 37-38years $ 200 Transmission and distribution 23 - 46 years 200 Common 4 - 42 years 200 Nuclear fuel in process and in reactor 6 years 200 Generation assets under capital lease 15 - 25 years -

(s) Payments-in-Lieu-of-Taxes The Company is required to make payments-in-lieu-of-taxes (PILOTS) for all operating taxes previously paid by LILCO, including gross income, gross earnings, property, Metropolitan Transportation Authority and certain taxes related to fuels used in utility operations. In addition, the Authority has entered into various PILOT arrangements for property it owns, upon which merchant generation and transmission is built.

(t) Allowance for BorrowedFunds Used During Construction The allowance for borrowed funds used during construction (AFUDC) is the net cost of borrowed funds used for construction purposes. AFUDC is not an item of current cash income. AFUDC is computed monthly on a portion of construction work in progress, and is shown as a net reduction in interest expense.

(u) Income Taxes The Authority is a political subdivision of the State of New York and, therefore, the Authority and its blended component unit are exempt from Federal, state, and local income taxes.

24 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 (v) Asset Retirement Obligation The Authority adopted SFAS No. 143, Accounting for Asset Retirement Obligations. An Asset Retirement Obligation (ARO) exists when there is a legal obligation associated with the retirement of a tangible long-lived asset that results from the acquisition, construction, or development and/or normal operation of the asset. LIPA, as an 18% owner of Nine Mile Point 2 (NMP2) Nuclear Power Station, has a legal obligation associated with its retirement. This obligation is offset by the capitalization of the obligation which is included in "Utility plant and property and equipment, net".

As of December 31, 2005 and 2004, respectively, the asset retirement obligation was approximately

$72.4 million and $68.3 million.

Additionally, during 2005, FASB Summary of Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations-an interpretation of SFAS No. 143 was issued. This Interpretation clarifies that the term conditional asset retirement obligation as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Prior to this interpretation, LIPA did not report an ARO on certain of its utility assets. However, as a result of this interpretation, approximately $3 million has been reclassified from accumulated depreciation, where it has been recorded previously, to the asset retirement obligation. The Company recorded an additional asset retirement obligation of $4 million and increased utility plant, and property and equipment. The required obligation under the standard was approximately $9 million.

(w) Long-Lived Assets Long-lived assets, such as property, plant, and equipment, and purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is assessed by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flow, an impairment charge to be recognized is measured by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of and assets held for sale are reported at the lower of the carrying amount or fair value less costs to sell, whether reported in continuing operations or in discontinued operations, and are no longer depreciated.

(x) Use of Estimates The accompanying financial statements were prepared in conformity with accounting principles generally accepted in the United States of America which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

25 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 (v) Reclassifications Certain prior year amounts have been reclassified in the financial statements to conform with the current year presentation.

(4) Risk Management The Authority is routinely exposed to commodity and interest rate risk. In order to mitigate such exposure, the Authority formed an Executive Risk Management Committee.

Fuel andpurchasedpower transactions:The Authority uses derivative financial instruments as detailed in the table below:

Fuel Derivative Transactions Volume Type of contract Duration per month Oil contracts (volumes in barrels):

Options Put Short Jan 06 - Dec 08 80,000-600,000 Call Long Jan 06 - Dec 08 80,000-600,000 Swap Long Jan 06 - Dec 08 20,000-535,000 Gas transactions (volumes in decatherms):

Put Short Jan 06 - Dec 08 435,000-3,255,000 Call Long Jan 06 - Dec 08 435,000-3,255,000 Swap Long Jan 06 - Dec 08 75,000-3,065,000 Basis transactions (volumes in decatherms):

Jan 06 - Mar 07 ** 140,000-1,240,500 Swap Long

• No ownership from January to April 2008

• • No ownership from April to October 2006 26 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 Interest Rate Transactions: The Authority has entered into several interest rate swap agreements with several counterparties to modify the effective interest rates on outstanding debt as detailed below (thousands of dollars):

December 31,2005 Notional Effective Type of Mark to Deferred amount date swap market gain (loss)

$ 150,000 11/12/1998 Floating to Fixed $ (11,134) (11,134) 100,000 11/12/1998 Floating to Fixed (8,168) (8,168) 587,225 6/1/2003 Floating to Fixed (a) (136,285) (40,257) 100,995 7/1/2004 Fixed to Floating (657) (657) 100,995 7/1/2004 Fixed to Floating (b) (619) (619) 502,090 7/1/2004 Basis Swap (c) (30,150) (13,945) 251,045 7/1/2004 Basis Swap (d) (15,165) (7,062) 251,045 7/1/2004 Basis Swap (d) (15,039) (6,936)

Total $ (217,217) (88,778) 116,000 11/1/2001 Fixed to Floating $ 4,623 4,623 116,000 4/1/2003 Floating to Fixed (b) (5,779) 1,716 Total $ (1,156) 6,339 (a) The Authority received an upfront premium totaling approximately $106 million.

(b) The Authority received an upfront premium totaling approximately $8 million.

(c) The Authority received an upfront premium totaling approximately $17.5 million.

(d) The Authority received an upfront premium totaling approximately $8.75 million.

(5) Rate Matters Under current New York State law, the Authority is empowered to set rates for electric service in the Service Area without the approval of the New York State Public Service Commission (PSC) or any other state regulatory body. However, the Authority has agreed, in connection with the approval of the 1998 merger of the Authority and LILCO (d/b/a LIPA) by the New York State Public Authorities Control Board (the PACB), that it will not impose any permanent increase, nor extend or re-establish any portion of a temporary rate increase, in average customer rates over a 12-month period in excess of 2.5% without approval of the PSC, following a full evidentiary hearing. Another of the PACB conditions requires that the Authority reduce average base rates within LIPA's service area by no less than 14% over a ten year period commencing on the date when LIPA began providing electric service, when measured against LILCO's base rates in effect on July 16, 1997 (excluding the impact of the Shoreham Property Tax Settlement, but adjusted to reflect emergency conditions and extraordinary unforeseeable events).

For a further discussion on rate matters, see note 12 of notes to basic financial statements.

27 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 The LIPA Act requires that any bond resolution of the Authority contain a covenant that it will at all times maintain rates, fees or charges sufficient to pay the costs of operation and maintenance of facilities owned or operated by the Company; PILOTS; renewals, replacements and capital additions; the principal of and interest on any obligations issued pursuant to such resolution as the same become due and payable, and to establish or maintain any reserves or other funds or accounts required or established by or pursuant to the terms of such resolution.

LIPA's tariff includes: (i) the FPPCA, to allow for adjustments to customers' bills to reflect changes in the cost of fuel and purchased power and related costs; (ii) a PILOTS recovery rider, which allows for rate adjustments to accommodate PILOTS; and (iii) a rider providing for the recovery of costs associated with the Shoreham Property Tax Settlement (credits and rebates).

28 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 (6) Utility Plant and Property and Equipment The following schedule summarizes the utility plant and property and equipment of the Authority as of December 31, 2005 (thousands of dollars):

Beginning Ending balance Additions Deletions balance Capital assets, not being depreciated:

Land $ 9,941 2,233 12,174 Retirement work in progress 6,850 15,043 725 21,168 Construction in progress 73,548 203.477 186.595 90,430 Total capital assets not being depreciated 90.339 220,753 187,320 123,772 Capital assets, being depreciated:

Generation - nuclear 700,915 2,439 703,354 Transmission and distribution 2,325,845 175,139 9,564 2,491,420 Common 4,724 12,744 13 17,455 Nuclear fuel in process and in reactor 46,513 11,174 57,687 Office equipment, furniture, and leasehold improvements 3,307 192 3 3,496 Generation assets under capital lease 944,398 403.431 1.347,829 Total capital assets being depreciated 4,025,702 605,119 9,580 4,621,241 Less accumulated depreciation for:

Generation - nuclear 132,829 26,404 159,233 Transmission and distribution 320,403 96,880 14,296 402,987 Common 807 2,347 13 3,141 Nuclear fuel in process and in reactor 37,656 5,806 43,462 Office equipment, furniture, and leasehold improvements 2,197 386 2,583 Generation assets under capital lease 82,046 46,915 128,961 Total accumulated depreciation 575,938 178.738 14,309 740,367 Net value of capital assets, being depreciated 3,449,764 426,381 (4,729) 3,880,874 Net value of all capital assets $ 3,540,103 647,134 182,591 4,004,646 In 2005, depreciation expense relat ed to capital assets was approximately $125 million.

29 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 The following schedule summarizes the utility plant and property and equipment of the Authority as of December 31, 2004 (thousands of dollars):

Beginning Ending balance Additions Deletions balance Capital assets, not being depreciated:

Land $ 9,833 108 9,941 Retirement work in progress 6,860 16,003 16,013 6,850 Construction in progress 29,806 184.786 141,044 73,548 Total capital assets not being depreciated 46,499 200,897 157,057 90,339 Capital assets, being depreciated:

Generation - nuclear 693,183 7,732 700,915 Transmission and distribution 2,207,033 132,546 13,734 2,325,845 Common 4,440 766 482 4,724 Nuclear fuel in process and in reactor 37,142 9,371 46,513 Office equipment, furniture, and leasehold improvements 2,920 387 3,307 Generation assets under capital lease 844.914 99,484 944,398 Total capital assets being depreciated 3,789.632 250,286 14,216 4,025,702 Less accumulated depreciation for:

Generation - nuclear 106,657 26,172 132,829 Transmission and distribution 260,665 89,466 29,728 320,403 Common 653 655 501 807 Nuclear fuel in process and in reactor 32,705 4,951 37,656 Office equipment, furniture, and leasehold improvements 1,853 344 2,197 Generation assets under capital lease 43,211 38,835 82,046 Total accumulated depreciation 445,744 160,423 30,229 575,938 Net value of capital assets, being depreciated 3,343,888 89,863 (16,013) 3,449,764 Net value of all capital assets $ 3,390,387 290,760 141,044 3,540,103 In 2004, depreciation expense relat ed to capital assets was approximately $116.6 million.

30 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 (7) Nine Mile Point Nuclear Power Station, Unit 2 (NMP2)

LIPA has an undivided 18% interest in Nine Mile Point 2 Nuclear Power Station (NMP2), located in Scriba, New York, operated by Constellation Nuclear LLC (Constellation).

LIPA's share of the rated capability of NMP2 is approximately 207 megawatts (MW). LIPA's net utility plant investment, excluding nuclear fuel, was approximately $544 million and $568 million as of December 31, 2005 and 2004, respectively. Generation from NMP2 and operating expenses incurred by NMP2 are shared by LIPA at its 18% ownership interest. LIPA is required to provide its share of financing for any capital additions to NMP2. Nuclear fuel costs associated with NMP2 are being amortized on the basis of the quantity of heat produced for the generation of electricity.

LIPA has an operating agreement for NMP2 with Constellation, which provides for a management committee comprised of one representative from each co-tenant. Constellation controls the operating and maintenance decisions of NMP2 in its role as operator. LIPA and Constellation have joint approval rights for the annual business plan, the annual budget and material changes to the budget. In addition to its involvement through the management committee, LIPA employs on-site nuclear oversight personnel to provide additional support to protect LIPA's interests.

Nuclear Plant Decommissioning LIPA is making provisions for decommissioning costs for NMP2 based on a site-specific study performed in 1995, as updated by LIPA's engineering consultants. LIPA's share of the total decommissioning costs for both the contaminated and noncontaminated portions is estimated to be approximately $72 million as of December 31, 2005, and is included in the balance sheet as a component of the asset retirement obligation.

LIPA maintains a trust fund for its share of the decommissioning costs of NMP2, which as of December 31, 2005 and 2004, had an approximate value of $59.0 million and $54.1 million, respectively.

Through continued deposits and investment returns being maintained within these trusts, the Company believes that the value of these trusts in 2046 will be sufficient to meet the Company's decommissioning obligations.

NMP2 Radioactive Waste Constellation has contracted with the U.S. Department of Energy (DOE) for disposal of high-level

.radioactive waste (spent fuel) from NMP2. Despite a court order reaffirming the DOE's obligation to accept spent nuclear fuel by January 31, 1998, the DOE has forecasted the start of operations of its high-level radioactive waste repository to be no earlier than 2010. LIPA has been advised by Constellation that the NMP2 spent fuel storage pool has a capacity for spent fuel that is adequate until 2012. If additional DOE schedule slippage should occur, the storage for NMP2 spent fuel, either at the plant or some alternative location, may be required. LIPA reimburses Constellation for its 18% share of the cost under the contract at a rate of $1.00 per megawatt hour of net generation, less a factor to account for transmission line losses. Such costs are included in the cost of fuel and purchased power.

Nuclear Plant Insurance Constellation procures public liability and property insurance for NMP2 and LIPA reimburses Constellation for its 18% share of those costs.

31 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 In November 2002, the Terrorism Risk Insurance Act (TRIA) of 2002 was enacted by the federal government. Under the TRIA, property and casualty insurance companies are required to offer insurance for losses resulting from Certified acts of terrorism. The United States Secretary of State and Attorney General determine certified acts of terrorism. The nuclear property and accidental outage insurance programs, as discussed later in this section provide coverage for Certified acts of terrorism.

Losses resulting from noncertified acts of terrorism are covered as a common occurrence, meaning that if noncertified terrorist acts occur against one or more commercial nuclear power plants insured by the insurer's of NMP2, within a 12-month period, such acts would be treated as one event and the owners of the currently..licensed nuclear power plants in the United States would share one full limit of liability (currently $3.24 billion).

The Price-Anderson Amendments Act mandates that nuclear power generators secure financial protection in the event of a nuclear accident. This protection must consist of two levels. The primary level provides liability insurance coverage of $300 million (the maximum amount available) in the event of a nuclear accident. If claims exceed that amount, a second level of protection is provided through a retrospective assessment of all licensed operating reactors. Currently, this "secondary financial protection" subjects each of the 104 presently licensed nuclear reactors in the United States to a retrospective assessment of up to

$100.6 million for each nuclear incident, payable at a rate not to exceed $10 million per year. LIPA's interest in NMP2 could expose it to a maximum potential loss of $18.1 million, per incident, through assessments of up to $1.8 million per year in the event of a serious nuclear accident at NMP2 or another licensed U.S. commercial nuclear reactor.

Constellation participates in the American Nuclear Insurers Master Worker Program that provides coverage for worker tort claims filed for radiation injuries. Effective January 1, 1998, this program was modified to provide coverage to all workers whose nuclear-related employment began on or after the commencement date of reactor operations. Waiving the right to make additional claims under the old policy was a condition for coverage under the new policy. The old and new policies are described below:

Nuclear worker claims reported on or after January 1, 1998 are covered by an insurance policy with an annual industry aggregate limit of $300 million for radiation injury claims against all those insured by this policy.

All nuclear worker claims reported prior to January 1, 1998 are still covered by the old policy.

Insureds under the old policies, with no current operations, are not required to purchase the newer policy described above, and may still make claims against the old policies through 2007. If radiation injury claims under these old policies exceed the policy reserves, all policyholders could be retroactively assessed, with LIPA's share being up to $300,000.

Constellation has also procured $500 million of primary nuclear property insurance and additional protection (including decontamination costs) of $1.25 billion of stand-alone excess property insurance and a $1.0 billion shared excess policy for Nine Mile Point through the Nuclear Electric Insurance Limited (NEIL). Each member of NEIL, including LIPA, is also subject to retrospective premium adjustments in the event losses at other member facilities exceed accumulated reserves. For its share of NMP2, LIPA could be assessed up to approximately $3.1 million per loss.

32 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 LIPA has obtained insurance coverage from NEIL for the expense incurred in purchasing replacement power during prolonged accidental outages. Under this program, coverage would commence twelve weeks after any accidental outage, with reimbursement from NEIL at the rate of approximately $630,000 per week for the first 52 weeks, reduced to $504,000 per week for an additional 110 weeks for the purchase of replacement power, with a maximum limit of $88.2 million over a three-year period.

NMP2 License Renewal In May 2004, Constellation submitted an application to extend the licensed life of NMP2 by 20 years. If successful, this would extend the license dates to the year 2046. The current review cycle history of the Nuclear Regulatory Commission (NRC) indicates that approval could be expected by the end of 2006.

To maximize its options, LIPA has agreed to fund a pro rata share of the license renewal costs up to the point of approval by the NRC. At the point of approval, LIPA will then have an option to participate in the extended license.

(8) Cash, and Cash Equivalents and Investments The Authority and LIPA each have distinct investment policies to manage the risks associated with each of their investment objectives.

(a) Authority The Authority's investments are managed by an external investment manager and consist of two accounts; the Operating Fund and the Rate Stabilization Fund. The Operating Fund is managed to meet the liquidity needs of the Authority and the Rate Stabilization Fund is managed to maximize the return on investment. The Authority must maintain a minimum balance of $150 million in the Rate Stabilization Fund as required by the Authority's bond covenants, however, the Authority has set an informal policy of maintaining a minimum balance of $250 million. Additionally, the Authority is required to maintain compensating balances of $1.2 million.

The Authority's investment policy places limits on investments by issuer and by security type and addresses various risks described below. The Board of Trustees of the Authority may also specifically authorize, as it deems appropriate, other investments that are consistent with the Authority's investment objective. The Authority reviews its investment policy on an annual basis to ensure continued effectiveness.

Investment Risks Credit Risk The Authority's permissible investments and related minimum credit ratings include U.S. Treasury and Federal Agency obligations (AAA), repurchase agreements (A-l), bankers' acceptances (AA- or Aa3), commercial paper (Al or P-l), corporate notes (AA- or Aa3), master notes (AA- or Aa3) and asset backed securities (AAA), certificates of deposit (AA- or Aa3), mutual funds (AAAm or AAAm-G), investment contracts (AA- or Aa3, municipal obligations (AA- or Aa3), and variable rate notes (no credit rating limit). The Authority's investment policy prohibits investments involving complex derivatives, reverse repurchase agreements, and short selling and arbitrage related investment activity.

33 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 Concentration of Credit Risk To address this risk, the Authority's investment policies have established limits such that no more than 5% of the investment portfolio may be invested in the securities of any one issuer with the exception of U.S. Treasury Obligations (100% maximum), each Federal agency (35%), repurchase agreements counterparties (less of 10% or $50 million), mutual funds (25% maximum) and investment contracts (10%).

Custodial Credit Risk The Authority believes that custodial credit risk related to its deposits and investments to be minimal as its guidelines stipulate that deposits and investments be held by a third-party custodian who may not otherwise be a counter-party to the transactions, and that all securities are held in the name of the Authority and that will be free and clear of any lien.

Custodial credit risk for deposits is the risk that in the event of a bank failure, the Authority's deposits may not be returned. The Authority's policy to address this risk requires that the custodian or depository bank have a long term credit rating of Aa3/AA. Custodians or depository banks not meeting this credit rating are required to provide collateral.

As of December 31, 2005 and 2004, the Authority had deposits of $24.6 million and $25.2 million respectively, of which approximately $12.8 million and $0.8 million were not collateralized or were uninsured. Uncollateralized balances were primarily the result of amounts temporarily held pending investment or disbursement. Collateral on the remaining deposits is held in the name of the Authority and range from 102% to 105% of the deposit balances.

Interest Rate Risk The Authority's policy states that all investments have maturities of 12 months or less, generally.

Investment maturities may exceed 12 months provided that the maturity does not exceed the expected disbursement date of those funds, the total average portfolio maturity is one year or less and no individual maturity exceeds three years, with the exception of U.S. Government obligations and investment contracts. The duration of the Authority's investment maturities are detailed in the chart below.

34 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 As of December 31, 2005 and 2004 the Authority had the following investments and maturities (amounts in thousands):

Investment Maturities 2005 Percent of Less than 3 months to I to Investment Type Fair value portfolio 3 months 1 year 3 years U.S. Treasury obligations $ 9,451 2% $ 9,451 Short term discount notes:

Commercial paper 267,087 33 267,087 - -

Federal agencies 153,916 57 153,916 - -

Master notes/money markets 15,728 3 15,728 - -

Cash & collateralized deposits 24,698 5 24.698 - -

Total $ 470,880 100% $ 461,429 9,451 Investment Maturities 2004 Percent of Less than 3 months to I to Investment Type Fair value portfolio 3 months 1 year 3 years U.S. Treasury obligations 60,000 15% $ 10,040 49,960 Variable rate Federal agency obligations 9,994 2 9,994 Variable rate corporate bonds 19,998 5 9,998 -- 10,000 Short term discount notes:

Commercial paper 255,472 62 255,472 --

Federal agencies 38,030 9 30,123 7,907 Master notes/money markets 4,316 1 4,316 -

Cash & collateralized deposits 25,158 6 25,158 - -

Total $ 412.968 100% $ 345.101 57,867 10.000 (b) LIPA LIPA maintains a separate investment policy applicable to the long term investments in the Nuclear Decommissioning Trust (NDT) which is held to meet LIPA's obligation with respect to the eventual decommission of LIPA's 18% interest in the Nine Mile Point 2 nuclear facility. LIPA guidelines detail permissible investments and portfolio restrictions. LIPA reviews it investment policy on an annual basis, or as required, to ensure continued effectiveness.

35 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 Investment Risks Credit Risk LIPA's guidelines minimize the risk by limiting permissible investments to include; obligations of the U.S. Government and its Agencies, corporate or other obligations with an A or better rating, mortgage obligations rated AA or higher, commercial paper with a rating of Al or P1, certificates of deposit, Eurodollar certificates of deposit and bankers acceptances of domestic banks with A+ rating or better, short term money market investment accounts that conform to the aforementioned permissible investments, portfolio funds of securities designed to replicate the overall market measured by the S&P 500 Index, and futures contracts on the S&P 500 Index in the futures markets.

The Board of Trustees authorized the use of equity investments as permissible vehicle within this portfolio in 2004 and limited the maximum exposure to 35%. The Nuclear Decommissioning Trust investment portfolio must be rebalanced quarterly at plus or minus 5% for equity investments. Fixed income securities held in the portfolio must maintain an average credit rating of AA or better with no more than 30% of the portfolio invested in notes and bonds rated A and no more than 20% of the portfolio invested in municipal securities.

Concentration of Credit Risk To address this risk, LIPA's investment policies have established limits such that more than 5% of the portfolio may be invested in the securities of any one issuer with the exception of U.S.

Government and its agencies securities. In addition, no more than 25% of the portfolio may be invested in securities of issuers in the same industry.

Custodial Credit Risk LIPA does not have a policy relative to custodial credit risk of its deposits, however, as a practical matter, LIPA defers to the policies of the Authority, as discussed above. LIPA's deposits at December 31, 2004 were fully collateralized.

Interest Rate Risk Due to the long term nature of the NDT asset, interest rate risk is managed to track the Lehman Brothers Government/Credit Bond Index. The portfolio's duration is required to fall within a range of 20% below the duration of the index and 10% above the duration of the index.

36 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 As of December 31, 2005 and 2004 LIPA had the following investments (amounts in thousands):

2005 Percent of Investment type Fair value portfolio Corporate notes and bonds $ 25,606 43%

Mortgage obligations 121 U.S. Government and its agencies obligations 22,430 38 Money market 105 Equity securities 11,668 19 Total $ 59,930 100%

2004 Percent of Investment type Fair value portfolio Corporate notes and bonds $ 22,379 41%

Mortgage obligations 149 U.S. Government and its agencies obligations 17,955 33 Money market 10,308 19 Deposits 3,293 7 Total 54,084 100%

The overall duration of the three individual accounts averaged 4.6 and 4.5 years at December 31, 2005 and 2004, respectively, and is within the limits described by LIPA's investment guidelines.

(9) Long-Term and Short-Term Debt The Authority financed the cost of the merger and the refinancing of certain of LILCO's outstanding debt by issuing approximately $6.73 billion aggregate principal amount of Electric System General Revenue Bonds and Electric System Subordinated Revenue Bonds (collectively, the Bonds). In conjunction with the issuance of the Bonds, LIPA and the Authority entered into a Financing Agreement, whereby LIPA transferred to the Authority all of its right, title and interest in and to the revenues generated from the operation of the transmission and distribution system, including the right to collect and receive the same. In exchange for the transfer of these rights to the Authority, LIPA received the proceeds of the Bonds evidenced by a Promissory Note.

The Bonds are secured by a Trust Estate as pledged under the Authority's Bond Resolution (the Resolution). The Trust Estate consists principally of the revenues generated by the operation of LIPA's transmission and distribution system and has been pledged by LIPA to the Authority.

37 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 The Company's bond and note indebtedness and other long-term liabilities as of December 31, 2005 are comprised of the following obligations (thousands of dollars):

Beginning Accretion/ Retirements/ Ending Due within balance additions refundings balance one year Authority debt:

Electric system general revenue bonds:

Series 1998A $ 2,157,793 7,962 72, 830 2,092,925 75,810 Series 1998B 711,580 711,580 Series 2000A 309,071 17,934 327,005 Series 2001A 300,000 300,000 Series 2001B-K 500,000 500,000 Series 2001L-P 316,000 316,000 Series 2003A 86,900 -- 19,500 67,400 13,930 Series 2003B 474,600 -- 74,000 400,600 112,585 Series 2003C 323,380 323,380 Series 2003D-O 587,225 587,225 Series 2004A 200.000 200,000 Subtotal - bonds 5,966,549 25,896 166.330 5,826,115 202.325 Electric system subordinate revenue bonds:

Series 1-3 525,000 525,000 Series 7 250,000 250,000 -

Series 8 187,345 -- 27,300 160,045 -

Subtotal - bonds net 962,345 -- 27,300 935,045 -

LIPA Debt:

NYSERDA notes 155,420 155,420 -

Subtotal - debt 155.420 155.420 -

Net unamortized discounts/premiums and deferred amortization (25,407) (2.712) (28.119) -

Total bonds and notes net of unamortized discounts/

premiums $ 7,058,907 23,184 193,630 6,88,461 202,325 Other long-term liabilities:

Deferred credits $ 85,323 5,433 22,155 68,601 Claims and damages 20,091 17,264 10,774 26,581 Capital lease obligation 862.352 403,431 46,915 1,218,868 121,813 Total other long-term liabilities $ 967,766 426,128 79,844 1,314,050 121,813 Additions to the Series 2000A and Series 1998A bonds represent the current accretion on the capital appreciation bonds.

38 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 The Company's bond and note indebtedness and other long-term liabilities as of December 31, 2004 are comprised of the following obligations (thousands of dollars):

Beginning Accretion/ Retirements/ Ending Due within balance additions refundings balance one year Authority debt:

Electric system general revenue bonds:

Series 1998A $ 2,219,636 8,137 69,!980 2,157,793 166,330 Series 1998B 744,205 32,i625 711,580 Series 2000A 292,123 16,948 - 309,071 Series 2001A 300,000 - 300,000 Series 2001B-K 500,000 - 500,000 Series 200IL-P 316,000 - 316,000 Series 2003A 106,400 19,:500 86,900 Series 2003B 511,575 36,.975 474,600 Series 2003C 323,380 - 323,380 Series 2003D-O ,CQ17 111C -587,225 Series 20D4A -200,000 - 200,000 Subtotal - bonds 5,900.544 225.085 159,1080 5.966.549 166.330 Electric system subordinate revenue bonds:

Series 1-3 525,000 - 525,000 Series 7 250,000 - 250,000 Series 8 214,645 27. 300 187.345 27.300 Subtotal - bonds net 989.645 27, 300 962.345 27.300 LIPA Debt:

NYSERDA notes 155.420 -- 155,420 Subtotal - debt 155,420 - 155.420 Net unamortized discounts/premiums and deferred amortization (23.286) (2.488) (367) (25,407)

Total bonds and notes net of unamortized discounts/

premiums $ 7.022.323 222.597 186.013 7,058.907 193.630 Other long-term liabilities:

Deferred credits $ 130,196 5,105 49,978 85,323 Claims and damages 21,481 5,019 6,409 20,091 Capital lease obligation 801,703 99,484 38.835 862.352 89,552 Total other long-term liabilities $ 953,380 109,608 95,222 967.766 89.552 Additions to the Series 2000A and Series 1998A bonds represent the current accretion on the capital appreciation bonds.

39 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 The Company's schedule of capitalization for the years ended December 31, 2005 and 2004 is as follows (thousands of dollars):

Interest December 31 Maturity rate Series 2005 2004 Electric system general Revenue bonds:

Serial bonds Annually to 2016 4.250% to 6.0000%a 1998 A $ 678,450 738,310 Term bonds December 1,2018 to 2029 5.000% to 5.750% a 1998 A 1,263,350 1,263,350 Capital appreciation bonds December 1,*2003 to 2028 4.400% to 5.3 00% a 1998 A 151,125 156,133 Serial bands Annually to 2016 4.000% to 5.250% a 1998 B 654,435 654,435 Term bonds April 1,2018 4.750% a 1998 B 57,145 57,145 Capital appreciation bonds June 1,2005 to 2029 5.000% to 5.950% a 2000 A 327,005 309,071 Serial bonds September 1,2013 to 2021 4.600% to 5.375% a 2001 A 21,960 21,960 Term bonds September 1,2025 to 2029 5.000% to 5.375% a 2001 A 278,040 278,040 Term bonds May 1,2033 3.250% b 2001 B 75,000 75,000 Term bonds May 1,2033 3.200% b 2001 C 25,000 25,000 Term bonds May 1,2033 3.200% b 2001 D 50,000 50,000 Term bonds May 1, 2033 3.300% b 2001 E 50,000 50,000 Term bonds May 1, 2033 3.150% b 2001 F 50,000 50,000 Term bonds May 1, 2033 3.050% b 2001 G 50,000 50,000 Term bonds May 1, 2033 3.150% b 2001 H 50,000 50,000 Term bonds May 1, 2033 3.150% b 20011I 50,000 50,000 Term bonds May 1, 2033 3.150% b 2001 J 50,000 50,000 Term bonds May 1,2033 2.950% b 2001 K 50,000 50,000 Term bonds May 1, 2033 5.375% a 2001 L 116,000 116,000 Term bonds May 1, 2033 3.100% b 2001 M 50,000 50,000 Term bonds May 1, 2033 3.100% b 2001 N 50,000 50,000 Term bonds May 1, 2033 3.200% b 2001 0 50,000 50,000 Term bonds May 1, 2033 3.200% b 2001 P 50,000 50,000 Serial bonds June 1, 2004 to 2009 3.00% to 5.00% a 2003 A 67,400 86,900 Serial bonds December 1, 2003 to 2014 3.00% to 5.25% a 2003 B 400,600 474,600 Serial bonds September 1, 2013 to 2028 4.25% to 5.50% a 2003 C 137,860 137,860 Term bonds September 1,2027 to 2033 5.00% to 5.25% a 2003 C 185,520 185,520 December 1, 2029 3.36% to 3.52% c 2003 D-11 293,625 293,625 December 1, 2029 2.85% to 3.25% b 2003 1-0 293,600 293,600 Serial bonds September 1, 2013 to 2025 3.80% to 4.875% a 2004 A 33,900 33,900 Term bonds September 1, 2029 to 2034 5.00% to 5.10% a 2004 A 166,100 166,100 Electric system subordinated Revenue bonds May 1,2033 3.36% to 3.56% c Series IA-3A 275,000 275,000 May 1,2033 3.65% to 3.72% d Series 113-313 250,000 250,000 April 1,2025 4.210% a Series?7 250,000 250,000 April 1, 2009 to 2012 4.000% to 5.250% a Series 8 160,045 187,345 Total general and subordinated revenue bonds 6.761,160 6,928,894 Commercial paper notes 2.90% to 3.08% b CP-1 100,000 100.000 40 40 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 Interest December 31 Maturity rate Series 2005 2004 NYSERDA Financing notes:

Pollution control revenue bonds March 1, 2016 5.150% a 1985 A,B S 108,020 108,020 Electric facilities revenue bonds November 1,2023 5.300% a 1993 B 29,600 29,600 October 1,2024 5.300% a 1994 A 2,600 2,600 August 1, 2025 5.300% a 1995 A 15,200 15,200 Total NYSERDA financing notes 155,420 155,420 Unamortized premium and deferred amortization (28,119) (25,407)

Total long-term debt 6,988,461 7,158,907 Less current maturities 202,325 193,630 Long-term debt 6,786,136 6,965,277 Net assets 51,620 31,620 Total capitalization S 6,837,756 6,996,897 a - Fixed rate b - Variable rate (rate presented is as of December 31, 2005); Auction rate mode reset at rates as determined by auction agent.

c - Variable rate (rate presented is as of December 31, 2005); Weekly interest rate mode reset at rates as determined by remarketing agent.

d - Variable rate (rate presented is as of December 31, 2005); Daily reset rate mode as determined by remarketing agent.

The debt service requirements for the Company's bonds as of December31, 2005 are as follows (thousands of dollars):

December 31,2005 Net swap Due Principal Interest payments Total 2006 202,325 298,724 10,467 511,516 2007 214,420 288,452 10,467 513,339 2008 225,955 277,590 10,467 514,012 2009 240,730 267,230 10,467 518,427 2010 224,295 256,334 10,467 491,096 2011-2015 1,061,410 1,133,370 53,972 2,248,752 2016-2020 1,143,430 921,245 55,829 2,120,504 2021-2025 1,309,390 698,463 50,771 2,058,624 2026-2030 1,610,155 424,073 28,879 2,063,107 2031-2035 1,183,810 95,403 -- 1,279,213 7,415,920 4,660,884 241,786 12,318,590 Unamortized discounts/premiums (28,119) (28,119)

Unaccreted interest on CABs (499,340) (499,340)

Total $ 6,888,461 4,660,884 241,786 11,791,131 41 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 Future debt service is calculated using rates in effect at December 31, 2005 for variable rate bonds. The net swap payment amounts were calculated by subtracting the future variable rate interest payments subject to swap agreements from the synthetic fixed rate amount intended to be achieved by the swap agreements.

Electric System General Revenue Bonds Series 2004A The Authority issued Series 2004A Electric System General Revenue Bonds totaling $200 million for various capital projects and to reimburse the Authority for capital expenditures funded with cash from operations. Series 2004A is comprised of Serial Bonds and Term Bonds with maturities beginning September 1, 2013 and continuing through 2034 and pays interest at a fixed rate every March 1 and September 1.

Electric System Subordinated Revenue Bonds Series 8 (SubSeriesA-H)

This Series is comprised of Current Interest Bonds issued as follows (thousands of dollars):

Mandatory Interest rate This series is comprised purchase date Maturity Principal to mandatory of subseries (April 1) (April 1) outstanding purchase date 8A 2009 $ 23,360 5.25%

8A 2009 2,500 4.13 8B 2009 17,160 4.30 8B 2009 10,000 5.25 8C 2010 25,225 5.00 8F 2006 2011 27,300 5.00 8G 2007 2012 27,300 5.00 8H 2008 2012 27,200 5.00

$ 160,045 Prior to the mandatory purchase date, the Authority determines to either purchase the Subseries or have such Subseries remarketed. Remarketed securities would become due at the maturity date or an earlier date as determined by the remarketing. The original interest rate on the debt issued will remain in effect until the mandatory purchase date, at which time the interest rate will change in accordance with market conditions at the time of remarketing. Principal, interest, and purchase price on the mandatory purchase date are secured by a financial guaranty insurance policy.

During the years ended December 31, 2005 and 2004, the Authority redeemed its SubSeries 8D and 8E Bonds, respectively, each totaling $27.3 million. SubSeries 8A through 8C bonds were remarketed and are in the Fixed Rate Mode, and pay interest on April 1 and October 1 of each year. The Authority intends to remarket its SubSeries 8F Bonds on the mandatory purchase date of April 1, 2006.

42 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 Commercial Paper Notes The Authority's Supplemental Bond Resolution authorizes the issuance of Commercial Paper Notes, Series CP-l through CP-3 (Notes) up to a maximum amount of $200 million. The aggregate principal amount of the Notes outstanding at any time may not exceed $200 million. In connection with the issuance of the Notes, the Authority has entered into a Letter of Credit and Reimbursement Agreement, expiring on June 15, 2006. The Notes do not have maturity dates of longer than 270 days from their date of issuance and as Notes mature, the Authority continually replaces them with additional Notes.

During 2005, the Authority issued an additional $50 million of Commercial Paper Notes to reimburse the Authority's treasury for capital projects. As of December 31, 2005, the Authority redeemed all of this issuance. As of December 31, 2005 and 2004, the Authority had Notes outstanding totaling $100 million.

The Company's short-term indebtedness as of December 31, 2005 and 2004 is comprised of the following obligations (thousands of dollars):

Beginning Ending balance Issuances Retirements balance Short term debt - CP-1 $ 100,000 - - 100,000 Short term debt - CP-2 - 50,000 (50,000) -

$ 100,000 50,000 (50,000) 100,000 43 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 Fair Values of Long-Term Debt The fair values of the Company's long-term debt as of December 31, 2005 and 2004 were as follows (thousands of dollars):

Fair value December 31 2005 2004 Electric System General Revenue Bonds, Series 1998 A $ 2,209,940 2,312,071 Electric System General Revenue Bonds, Series 1998 B 736,457 762,682 Electric System General Revenue Bonds, Series 2000 A 389,732 360,780 Electric System General Revenue Bonds, Series 2001 A 314,299 305,863 Electric System General Revenue Bonds, Series 2001 B through K 500,000 500,000 Electric System General Revenue Bonds, Series 2001 L through P 322,162 313,736 Electric System General Revenue Bonds, Series 2003 A 69,327 90,488 Electric System General Revenue Bonds, Series 2003 B 423,017 500,441 Electric System General Revenue Bonds, Series 2003 C 340,891 331,846 Electric System General Revenue Bonds, Series 2003 D through 0 587,225 587,225 Electric System General Revenue Bonds, Series 2004 A 207,989 178,644 Electric System Subordinated Revenue Bonds, Series 1-3 and 1-6 525,000 525,000 Electric System Subordinated Revenue Bonds, Series 7 250,000 250,000 Electric System Subordinated Revenue Bonds, Series 8 (subseries A-H) 165,337 199,164 Electric System Commercial Paper Notes, CP-1 100,000 100,000 NYSERDA Notes 155,420 156,440 Total $ 7,296,796 7,474,380 (10) Retirement Plans The Authority participates in the New York State Employees' Retirement System (the System), which is a cost-sharing, multi-employer, and public employee retirement system. The plan benefits are provided under the provisions of the New York State Retirement and Social Security Law that are guaranteed by the State Constitution and may be amended only by the State Legislature. For full time employees, membership in and annual contributions to the System are required by the New York State Retirement and Social Security Law. The System offers plans and benefits related to years of service and final average salary, and, effective July 17, 1998; all benefits generally vest after five years of accredited service.

44 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 Members of the System with less than "10 years of service or 10 years of membership" contribute 3% of their gross salaries and the Authority pays the balance of the annual contributions for these employees.

Effective October 1, 2000, members of the System with at least 10 years of service or membership no longer contribute 3% of their gross salaries. The Authority pays the entire amount of the annual contributions of these employees.

Under this plan, the Authority's required contributions and payments made to the System were approximately $1.3 million, $867,000, and $426,000, for the years ended December 31, 2005, 2004, and 2003, respectively. Contributions are made in accordance with funding requirements determined by the actuary of the System using the aggregate cost method.

The State of New York and the various local governmental units and agencies which participate in the Retirement System are jointly represented, and it is not possible to determine the actuarial computed value of benefits for the Authority on a separate basis. The New York State Employees' Retirement System issues a publicly available financial report. The report may be obtained from the New York State and Local Retirement Systems, 110 State Street, Albany, New York 12244.

(11) Commitments and Contingencies (a) PowerSupply Agreement The PSA provides for the sales to LIPA by KeySpan of all of the capacity and, to the extent necessary, energy from the oil and gas-fire generating plants on Long Island formerly owned by LILCO. Such sales of capacity and energy are made at cost-based wholesale rates regulated by the Federal Energy Regulatory Commission (FERC). The rates may be modified in accordance with the terms of the PSA for: i) agreed upon labor and expense indices applied to the base year; ii) a return of and return on net capital additions, which require approval by the Authority; and iii) reasonably incurred expenses that are outside of the control of KeySpan. The PSA rates were reset in 2004, and, in accordance with the agreement, will be reset again in 2009. Between 2004 and 2009, the rates will be adjusted annually in accordance with the formula established in the PSA. The annual capacity charge in 2005, was approximately $316 million, and the variable charge remained unchanged at

$0.90/Mwh.

The PSA provides incentives and penalties for up to $4 million annually, to maintain the output capability of the facilities, as measured by annual industry-standard tests of operating capability, and to maintain/or make capital improvements which benefit plant availability. The performance incentives averaged approximately $4 million in 2005 and 2004.

(b) PurchasedPower and TransmissionAgreements LIPA has contracts with numerous Independent Power Producers (IPPs) and the New York Power Authority (NYPA) for electric generating capacity. Under the terms of the 2004 amended agreement with NYPA, which will expire in April 2020, LIPA may purchase up to 100% of the electric energy produced at the NYPA facility located within LIPA's service territory at Holtsville, New York. LIPA is required to reimburse NYPA for the minimum debt service payments and to make fixed nonenergy payments associated with operating and maintaining the plant.

45 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 With respect to contracts entered into with the IPPs, LIPA is obligated to purchase all the energy they make available to LIPA at prices that often exceed current market prices. However, LIPA has no obligation to the IPPs if they fail to deliver energy.

LIPA also has a contract with NYPA for firm transmission (wheeling) capacity in connection with a transmission cable that was constructed, in part, for the benefit of LIPA. With the inception of the New York Independent System Operator (NYISO) on November 18, 1999, this contract was provided with "grandfathered rights" status. Grandfathered rights allow the contract parties to continue business as they did prior to the implementation of the NYISO. That is, the concept of firm physical transmission service continues. LIPA was provided with the opportunity to convert its grandfathered rights for Existing Transmission Agreements (ETAs) into Transmission Congestion Contracts (TCCs). TCCs provide an alternative to physical transmission reservations, which were required to move energy from point A to point B prior to the NYISO. Under the rules of the NYISO, energy can be moved from point A to point B without a transmission reservation however, the entity moving such energy is required to pay a tolling fee to the owner of the TCC. This tolling fee is called transmission congestion and is set by the NYISO.

Although LIPA has converted its ETA's into TCCs, LIPA will continue to pay all transmission charges per the ETAs, which expire in 2020. In return, LIPA has the right to receive revenues from congestion charges. All such charges and revenue associated with the TCCs are considered components of or reductions to fuel and purchased power costs, and as such are included in the FPPCA calculation.

In addition, in 2000, the Company entered into a lease for a submarine cable running between Connecticut and Long Island whereby LIPA would be entitled to up to 330 megawatts of transmission capacity. The cable was not able to obtain an operating license, as it had been determined that several sections of the cable were not buried to depths required by its permits.

During 2003, the Department of Energy (DOE) issued an emergency order allowing the cable to operate. Because the cable owner has not been able to obtain an operating license, the Authority was under no obligation to remit payments to the owner based on the 2000 lease agreement. As a result, LIPA entered into an interim agreement with the cable owner which established LIPA's ability to pay for 330 megawatts of capacity at a discounted rate from the original lease agreement during the term of the emergency order. In May 2004, the DOE lifted the emergency order.

46 (Continued)

LONG ISLAND POWER AUTHORITY (A Comp6fient Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 To resolve the outstanding issues associated with the cable, among other things, LIPA entered into a June 24, 2004, Settlement Agreement with certain Connecticut regulators, the cable owner and others. The Settlement Agreement provided for the immediate re-energization and operation of the cable subject to certain conditions, such as the cable meeting the depth requirements under its Connecticut permits. LIPA and the cable owner have negotiated the terms of a Bridge Agreement, which allows LIPA to utilize the cable during the period June 27, 2004 (when the cable was energized pursuant to the Settlement Agreement) to July 1, 2007, which is the new target date for initial commercial operation of the cable. Under the Bridge Agreement, LIPA may purchase 330 MW of firm transmission capacity at a discount from the rate contained in the original lease agreement. LIPA also entered into an amendment to the original agreement with the cable owner extending the original term of the agreement from 20 to 25 years, at the same rate set in the original agreement.

As provided by LIPA's tariff, the costs of all of the facilities noted above will be includable in the calculation of Fuel and Purchased Power Cost. As such, these costs will be recoverable through the FPPCA.

The following table represents LIPA's commitments under purchased power and transmission contracts (thousands of dollars):

Purchased power and transmission contracts Firm Total PPA transmission IPPs* business*

For the years ended:

2006 $ 34,474 45,033 168,900 248,407 2007 34,992 47,160 154,300 236,452 2008 35,528 48,866 147,400 231,794 2009 36,083 45,331 121,000 202,414 2010 36,656 45,878 62,400 144,934 2011 through 2015 173,395 235,507 281,700 690,602 2016 through 2020 170,195 246,631 12,600 429,426 2021 through 2025 - 179,991 179,991 2026 through 2030 186,278 186,278 2031 through 2035 - 89,415 89,415 Total $ 521,323 1,170,090 948,300 2,639,713

• Assumes full performance by NYPA and the IPPs.

47 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 (c) AdditionalPowerSupplies Purchase Power Agreements The Company has entered into Power Purchase Agreements (PPA's) with several private companies to develop and operate 17 generating units at sites throughout Long Island. All of the PPA's but one provide for 100% of the capacity, totaling approximately 735 MWs (and energy if needed), for the term of each contract, which vary in duration from three to 25 years from contract initiation date.

The remaining contract provides the Company with capacity and/or energy of up to 10MW, and is for a term of 30 years.

In accordance with the provisions of FASB Emerging Issues Task Force Issue No. 01-8, Determining Whether an Arrangements a Lease and SFAS No. 13, Accountingfor Leases, 14 of the generating units, have been accounted for as capitalized lease obligations, whereas the remaining units, are accounted for as operating leases.

The following table represents LIPA's minimum payments under its capacity and/or energy contracts (thousands of dollars):

Purchase Power Agreements Capital Operating Minimum lease/rental payments:

2006 $ 121,813 13,613 2007 121,380 13,639 2008 119,954 11,686 2009 119,108 1,813 2010 118,577 1,818 2011 through 2015 596,305 9,182 2016 through 2020 442,191 9,342 2021 through 2025 233,522 9,519 2026 through 2030 17,101 9,715 2031 through 2035 6,594 Total 1,889,951 86,921

.Less imputed interest 671,083 Net present value $ 1,218,868 86,921 48 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Note' to Basic Financial Statements December 31, 2005 and 2004 (d) Office Lease The Authority entered into a noncancelable office lease agreement through January 31, 2011. The future minimum payments under the lease are as follows (thousands of dollars):

Year ended December 3 1:

2006 $ 1,338 2007 1,388 2008 1,440 2009 1,494 2010 1,550 2011 129 Total $ 7,339 Rental expense for the office lease amounted to approximately $1.4 million for the years ended December 31, 2005 and 2004.

(e) InsurancePrograms The Authority's insurance program is comprised of a combination of policies from major insurance companies, self-insurance and contractual transfer of liability, including naming the Authority as an additional insured and indemnification.

The Authority has purchased insurance from the State of New York to provide against claims arising from workers' compensation. Liability related to construction projects and similar risks is transferred through contractual indemnification and compliance with Authority insurance requirements. The Authority also has various insurance coverages on its interest in Nine Mile Point Nuclear Power Station, Unit 2 as disclosed in detail in footnote 7.

The Authority is self insured for property damage to its transmission and distribution system and up to $3 million for general liability, including automobile liability. The Authority purchased commercially available excess general liability insurance for claims above the $3 million self insurance provision.

49 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 (12) Legal Proceedings (a) Authority to Set Rates Lawsuits have been commenced as class actions, and additional lawsuits threatened, challenging the steps LIPA has taken to increase its rates to reflect increases in its fuel costs. Among other allegations, the Plaintiffs contend that such increases violate certain conditions imposed on LIPA by the New York State Public Authorities Control Board in 1997. These lawsuits also repeat several criticisms directed at LIPA in a report issued by the New York State Comptroller in December 2005 which, among other things, took issue with the methodology used by LIPA in applying its FPPCA and criticized the increases in rates which have resulted from application of the FPPCA. LIPA believes that its rate structure, including the FPPCA, complies with applicable legal requirements and that the methodology it uses to calculate the FPPCA is correct. Plaintiffs seek injunctive relief and an unspecified amount of damages on behalf of themselves and other class members. LIPA will vigorously contest these cases and expects to prevail. If the Authority does not prevail in this litigation, it may influence the timing and size of rate increases implemented by the Authority and/or require (i) the modification of the plan to accelerate retirement of debt (ii) the withdrawal of funds from the Rate Stabilization Fund to avoid or minimize rate increases, or (iii) other action necessary to meet any required conditions.

(b) Environmental In connection with the LIPA/LILCO Merger (the "Merger"), KeySpan and LIPA entered into Liabilities Undertaking and Indemnification Agreements which, when taken together, provide, generally, that environmental liabilities will be divided between KeySpan and LIPA on the basis of whether they relate to assets transferred to KeySpan or retained by LIPA as part of the Merger. In addition, to clarify and supplement these agreements, KeySpan and LIPA also entered into an agreement to allocate between them certain liabilities, including environmental liabilities, arising from events occurring prior to the Merger and relating to the business and operations to be conducted by LIPA after the Merger (the Retained Business) and to the business and operations to be conducted by KeySpan after the Merger (the Transferred Business).

KeySpan is responsible for all liabilities arising from all manufactured gas plant operations (MGP Sites), including those currently or formerly operated by KeySpan or any of its predecessors, whether or not such MGP Sites related to the Transferred Business or the Retained Business. In addition, KeySpan is liable for all environmental liabilities traceable to the Transferred Business and certain scheduled environmental liabilities. Environmental liabilities that arise from the nonnuclear generating business may be recoverable by KeySpan as part of the capacity charge under the PSA.

LIPA is responsible for all environmental liabilities traceable to the Retained Business and certain scheduled environmental liabilities.

Environmental liabilities that existed as of the date of the Merger that are untraceable, including untraceable liabilities that arise out of common and/or shared services have been allocated 53.6% to LIPA and 46.4% to KeySpan, as provided for in the Merger.

so (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 (c) EnvironmentalMattersRetained by LIPA Long Island Sound Transmission Cables - The Connecticut Department of Environmental Protection (DEP) and the New York State Department of Environmental Conservation (DEC) separately have issued Administrative Consent Orders (ACOs) in connection with releases of insulating fluid from an electric transmission cable system located under the Long Island Sound that LIPA owns jointly with the Connecticut Light and Power Company (CL&P) (the "1385 Cable"). The ACOs require the submission of a series of reports and studies describing cable system condition, operation and repair practices, alternatives for cable improvements or replacement, and environmental impacts associated with prior leaks of fluid into the Long Island Sound. Pursuant to the June 24, 2004 Settlement Agreement (as referenced above) LIPA and CL&P agreed to undertake good faith negotiations on all contracts and other arrangements necessary for the removal and replacement of the 1385 Cable and to complete such negotiations no later than October 1, 2004. LIPA and CL&P further agreed to develop and implement a plan for such replacement on a schedule approved by the Commissioner of DEP. LIPA and CL&P have completed such negotiations, entered into two agreements with Northeast Utilities Service Company (NUSCO) relating to the use and replacement of the 1385 Cable, and submitted an implementation plan for such replacement, which was approved by the DEP. Replacement of the 1385 Cable is being procured by NUSCO on behalf of both LIPA and CL&P, and is expected to be completed in 2008.

In November 2002, a work boat, owned and operated by a third party, dragged its anchor, causing extensive damage to four of the seven cables of the 1385 cable and the release of a minimal amount of dielectric cable fluid into the Long Island Sound. The work boat had been at the cable site working as part of a large natural gas pipeline project. Temporary repairs were promptly carried out (the cable ends were capped) and permanent repairs completed in June 2003. Litigation arising from the incident commenced in December 2002 and in that litigation LIPA and CL&P aggressively pursued the owner of the work boat as well as the other parties involved in the natural gas pipeline project and who were involved in this incident. As a result of a voluntary mediation in February 2005, LIPA, CL&P and their insurance underwriters reached a settlement agreement with the owner of the work boat and the other parties, which was completed in April 2005.

The same natural gas pipeline project also resulted in another anchor drag incident in February 2003, which damaged the Y-49 Cable, a facility owned by NYPA but maintained by LIPA as the primary user. Here, a large barge involved in the project dragged its anchor resulting in the damage to one of the four cables of this facility. Temporary repairs (cable was capped) were completed within ten days and permanent repairs were done by September 2003. Litigation arising from the incident commenced in August 2003. LIPA, as well as NYPA and its property damage insurer are actively engaged in litigation against the barge owner as well as the other parties involved in the incident.

51 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 Simazine. Simazine is a commercially available herbicide manufactured by Novartis that was used by LILCO as a defoliant until 1993 under the direction of a New York State Certified Pesticide Applicator. Simazine contamination was found in groundwater at one of the LIPA substations in 1997. LIPA has conducted studies and monitoring activities in connection with this herbicide and is currently working cooperatively with the DEC and others in this matter. Results of these studies, and discussion with the regulatory agencies, have indicated that the environmental impact of this contamination is minimal and remediation work has been completed. However, pending the final conclusion of agency action on this matter, the liability, if any, resulting from the use of this herbicide cannot yet be determined. Nevertheless,, LIPA does not believe that it will have a material adverse effect on its financial position, cash flows, or results of operations.

Superfund Sites - Under Section 107(a) of the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA, also commonly referred to as the Superfund Legislation), parties who generated or arranged for disposal of hazardous substances are liable for costs incurred by the Environmental Protection Agency (EPA) or others who are responding to a release or threat of release of the hazardous substances.

Metal Bank- In December 1997, the EPA issued its Record of Decision (ROD), in connection with the remediation of a licensed disposal site located in Philadelphia, Pennsylvania, and operated by Metal Bank of America. In the ROD, the EPA estimated that the present cost of the selected remedy for the site is $17.3 million. In June 1998, the EPA issued a unilateral administrative order to 13 Potential Responsible Parties (PRPs), including LIPA, for the remedial design and for remedial action at the site. Under a PRP participation agreement, LIPA is responsible for 7.95% of the costs associated with implementing the remedy. LIPA has recorded a liability equal to its estimated cost representing its estimated share of the additional cost to remediate this site. The liability phase of the case was tried in the fall of 2002, which resulted in a finding of liability against Metal Bank in January 2003. At a March, 2003 conference before the federal judge, the court ordered that the second stage trial (determination of the final remedy) be held on November 1, 2003. In May, 2003, the Metal Bank parties filed for Federal Bankruptcy protection under Chapter 11, resulting in a reorganization plan that obligated the emerging entity to fund $13.25 million of the final remedy with no further obligation. In 2003, all the parties (EPA, the PRPs, and the two Schorsch brothers

[owners who were adjudicated liable early 2003 along with the Metal Bank parties]) entered into nonbinding mediation of two issues: (i) the scope of the remedy, and (ii) whether and how much the Schorsch brothers are prepared to contribute. As a result of that mediation, a final global settlement was negotiated, which did not require any monetary payment from the PRPs, but required the collective payment of $9.6 million from the Schorsch brothers. In 2005, Final Consent Decrees were published for public comment, the public hearing was held, and the Federal Judge is expected to shortly approve the Decrees, making all the settlement terms final, and formally ending the litigation.

Shortly, the Utilities Group (of which LIPA is a party) expects to submit to the EPA for its approval the Final Remedial Design Plan, and approval is expected in the first half of 2006. As a result of the entry of the Consent Decrees, the Utilities Group should be paid approximately $4 million by the defendant Schorsch brothers, which the Utilities Group intends to retain as a reserve should a contingency arise and the $13.25 million (funding of which is now ready to begin) by the Metal Bank successor in bankruptcy for the remedial work be insufficient. Based on the above, the Utilities Group expects remediation work to commence in 2006.

52 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 PCB Treatment Inc. - LILCO has also been named a PRP for disposal sites in Kansas City, Kansas and Kansas City, Missouri. The two sites were used by a company named PCE Treatment, Inc. from 1982 until 1987 for the storage, processing, and treatment of electric equipment, oils and other materials containing Polychlorinated Biphenyls (PCBs). According to the EPA, the buildings and certain soil areas outside the buildings are contaminated with PCBs. Certain of the PRPs, including LILCO and several other utilities, formed a group, signed a consent order and investigated environmental conditions at these properties. The work required under this consent order has been completed, and the PRPs, including LIPA, recently signed a second consent order that obligates them to clean up and restore the two contaminated properties. LIPA has been determined to be responsible for less than 1% of the materials that were shipped to this site. Although LIPA is currently unable to determine its precise liability for costs to remediate these sites, LIPA does not believe that this liability will have a material adverse effect on its financial position, cash flows or results of operations.

Environmental Matters Which May be Recoverable from LIPA by KeySpan Through the PSA Asharoken. In March 1996, the Village of Asharoken (the Village) filed a lawsuit against LILCO in the New York Supreme Court, Suffolk County (Incorporated Village of Asharoken, New York, et al.

v. Long Island Lighting Company). Although the Village's negligence claims were dismissed, the causes of action sounding in nuisance remain at issue. Specifically, the Village seeks injunctive relief based upon allegations that the design and construction of the Northport Power Plant upset the littoral drift of sand in the area, thereby causing beach erosion. In a related matter, certain individual residents of the Village commenced an action in New York Supreme Court Suffolk County seeking similar relief (Sbarro v. Long Island Lighting Company). The cases were tried jointly before a judge without a jury. The trial was completed in December 2002 and the parties filed post-trial briefs in March 2003. Since that time, the judge passed away and the case has been reassigned. The parties have agreed that the new judge can decide the case on the existing and supplemental record in lieu of a new trial. Liability, if any, resulting from this proceeding cannot yet be determined. However, LIPA does not believe that this proceeding will have a material adverse effect on its financial position, cash flows or results of operations.

Asbestos Proceedings Litigation is pending in State Court against LIPA, LILCO, KeySpan and various other defendants, involving thousands of plaintiffs seeking damages for personal injuries or wrongful death allegedly caused by exposure to asbestos. The cases for which LIPA may have financial responsibility involve employees of various contractors and subcontractors engaged in the construction or renovation of one or more of LILCO's six major power plants. These cases include extraordinarily large damage claims, which have historically proven to be excessive. The actual aggregate amount paid to plaintiffs alleging exposure to asbestos at LILCO power plants over the years has not been material to LIPA. Due to the nature of how these cases are litigated, it is difficult to determine how many of the remaining cases that have been filed (or of those that will be filed in the future) involve plaintiffs who were exposed to asbestos at any of the LILCO power plants. Based upon experience, it is likely that LIPA will have financial responsibility in a significantly smaller percentage of cases than are currently pending (or which will be filed in the future) involving plaintiffs who allege exposure to asbestos at any of the LILCO power plants.

53 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 Environmental Matters Which are Currently Untraceable for Which LIPA Could Have Responsibility Other Superfund Sites. The Attorney General is in negotiations with LIPA and other parties to achieve settlements at two of three municipal landfills where LILCO allegedly disposed of hazardous substances. The landfills are located in Towns of North Hempstead (the Port Washington Landfill) and Southampton, (the North Sea Landfill). The other municipal landfill where LILCO allegedly disposed of hazardous substances is in the Town of Huntington (the East Northport Landfill).All three landfills have been remediated and the Attorney General is seeking to recover the monies spent by the State in remediating the sites. The East Northport Landfill site was settled with the parties, resulting in an Order on Consent issued by the Attorney General on October 29, 2004. LIPA's share of the settlement was $173,800. The other two sites are still open and the subject of tolling agreements to extend the statute of limitations so that the State does not have to initiate litigation in order to achieve settlements with the various parties. LIPA's share of alleged liability at each site has not been established. LIPA was also served with a Request for Information by the Attorney General seeking information related to LILCO's activities at the Babylon Landfill Site in the Town of Babylon between 1946 and 1992. LIPA has responded to that request even though the statute of limitations has run against the Attorney General for seeking recovery against LIPA. The other potentially responsible parties who have signed tolling agreements could, however, bring an action against LIPA if they are sued by the Attorney General.

Other Matters East End Property Company #1, LLC, et al. v. Richard M. Kessel and The Long Island Power Authority, et al. In January 2006 litigation was commenced against the Authority, among others, contending that certain actions taken by it in connection with the power purchase agreement the Authority entered into with Caithness Long Island LLC ("Caithness"), the proposed construction by Caithness of a power plant in Brookhaven and the possible extension of the Iroquois Pipeline to the plant violate State environmental laws and other State laws and regulations. Plaintiff seeks, among other things, to annul actions the Authority has taken in connection with the power purchase agreement, to enjoin any action taken in furtherance of such agreement and to declare actions taken by the Authority in connection with the extension of the Iroquois Pipeline to be void. The Authority will file its answer to the complaint on March 1, 2006 and will vigorously contest this litigation.

LIPA may from time to time become a party to various legal proceedings arising in the ordinary course of its business. In the judgment of the Authority and LIPA, these matters will not individually or in the aggregate, have a material effect on the financial position, results of operations or cash flows of LIPA.

54 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Notes to Basic Financial Statements December 31, 2005 and 2004 Future Environmental Compliance Obligations LIPA, through its contractual obligations to KeySpan under the PSA and the MSA, is subject to the cost of compliance with various current and potential future environmental regulations as promulgated by the federal government and by state and local governments with respect to environmental matters, such as emission of air pollutants, cooling water for generation, the handling and disposal of toxic substances and hazardous and solid wastes, and the handling and use of chemical products. Electric utility companies generally use or generate a range of pollutants, potentially hazardous products and by-products that are the focus of such regulation. LIPA is also subject to state laws regarding environmental approval and certification of proposed major transmission facilities.

From time to time environmental laws, regulations and compliance programs may require changes in KeySpan's operations and facilities, and may increase the cost of energy delivery service. These costs may be reduced in the future, dependent on a capacity ramp down right that is available to LIPA beginning in 2008, the same time period where several compliance obligations occur.

Historically, rate recovery has been authorized for environmental compliance costs.

The Clean Air Act Amendments of 1990 (1990 Amendments) limit emissions of sulfur dioxide (S02) and nitrogen oxides (NOx). The U.S. Environmental Protection Agency (EPA) allocates annual sulfur dioxide emissions allowances to each of the PSA units based historical output. NOx are regulated on a regional level through the Ozone Transportation Commission, and are also controlled through allowance allocations. The PSA units are expected to continue to achieve cost effective compliance with these emission control requirements through capital expenditures, the use of natural gas fuel, and the purchase of emission allowances when necessary. LIPA may be required to purchase additional allowances above the PSA unit allocations based on changes in fuel prices.

Future requirements of the 1990 Amendments may require further reduction of S02 and NOx emissions, as well as new limits on mercury and nickel emissions. However, specific control requirements have not been determined by the EPA, and the costs, if any cannot be estimated at this time.

In 2003 the State of New York promulgated separate regulations that would further limit S02 and NOx beginning in 2004. The PSA units are expected to comply with the NOx requirements without additional material expenditures, and utilize lower sulfur fuel to meet the S02 regulations at an approximate cost of $20 million annually from 2005 through 2007. Further fuel sulfur reductions may be required in 2008 and beyond. In 2005, seven Northeast states signed a Memorandum of Understanding called the Regional Greenhouse Gas Initiative (RGGI) for the purpose of capping and then reducing greenhouse gas emissions from power plants. Several similar initiatives are also being considered at the federal level. It is not possible at this time to predict the nature of the requirements that may be imposed, nor their potential operational or financial impacts but the ability of the major PSA units to burn lower C02 emitting natural gas provides compliance flexibility for these units.

55 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Note's to Basic Financial Statemehts December 31, 2005 and 2004 In March 2005, the Federal Clean Air Interstate Rule was promulgated, requiring further reduction of S02 and NOx emissions. Depending on the outcome of one or more legal challenges, compliance requirements for NOx reduction would begin in 2009, and could require capital expenditures for emission control equipment on the order of $25 million to $35 million from 2006-2009. S02 reductions if required are expected to be achieved through the use of lower sulfur fuels or the surrender of excess emission allowances. Another rule issued in March of 2005, the Clean Air Mercury Rule (CAMR) set new limits for mercury emissions from coal fueled plants. These do not apply to the PSA units, The rule making process considered, but ultimately did not determine to regulate, Nickel emissions from oil fired units which would have affected some PSA units. Some aspects of CAMR are being litigated. Accordingly, it can not be determined whether EPA's decision not to regulate nickel will be sustained or whether any future compliance obligations will be imposed.

LIPA and the DEC are parties to a 1998 Consent Order for opacity, for which LIPA pays certain fines for exceeding the opacity limits. While in the past these fines have not been material, the DEC recently issued a draft industry-wide guidance that would increase penalties to as much as much as

$1 million per violation.

The Clean Water Act (CWA) requires that electric generating stations hold State Pollutant Discharge Elimination System (SPDES) permits, which reflect water quality considerations for the protection of the environment. Additional capital expenditures may be required by the New York State Department of Environmental Conservation (DEC) upon the periodic renewal of these water discharge permits due to recently promulgated changes in Section 316(b) of the CWA. KeySpan is undertaking the study of the impact of current permit conditions on aquatic resources in consultation with the DEC. The nature and extent of any expenditures cannot be determined until ongoing analysis of the impacts and mitigation discussions with NYSDEC are completed. At this time, compliance estimates range from $20 to $40 million in the 2006-2010 timeframe.

(13) Subsequent Events Strategic Organization Review In August 2004, the Authority began an extensive analysis of its organizational structure. The purpose of the review was to decide whether the Authority, as currently organized and governed, was in the best position to provide Long Island with reliable power at the lowest possible cost over the long term. The review also evaluated whether the Authority should exercise its option to acquire the former LILCO on-Island generation consisting of 53 generating units at 13 locations totaling approximately 4,000 megawatts (the "GPRA Option"). In December 2005, the Authority announced that it would remain in its current structure as a governmental authority and retain its public/private partnership model. The Authority also announced that, in connection with this determination, it had reached an agreement in principle with KeySpan to (i) substantially amend the Management Services Agreement between the Authority and KeySpan Electric Services LLC (the "MSA") and extend its term to December 31, 2013 (ii) settle certain disputes with KeySpan and the KeySpan Subs and (iii) provide the Authority with an option to acquire two of KeySpan's generating facilities with a combined capacity of 450 megawatts (the Barrett and Far Rockaway plants).

56 (Continued)

LONG ISLAND POWER AUTHORITY (A Component Unit of The State of New York)

Noted to Basic Financial Statements December 31, 2005 and 2004 In January, 2006 LIPA entered into definitive agreements to amend the MSA and certain other operating agreements entered into with certain of the KeySpan Subs, subject to certain governmental approvals and other conditions. LIPA also entered into a Settlement Agreement, dated as of January 1, 2006 (the "2006 Settlement Agreement"), with KeySpan and certain of the KeySpan Subs to resolve certain outstanding disputes. LIPA will receive approximately $120 million in payments or credits pursuant to the 2006 Settlement Agreement. LIPA has announced that it will reserve a portion of such amount to allow it to avoid increasing its electric rates through 2007, absent a world-wide energy crisis. In addition, LIPA expects to pay down approximately $25 million of its outstanding debt and provide each residential customer with a one-time refund of $35. LIPA also entered into an option agreement (the "2006 Option Agreement") with KeySpan Generation LLC ("GENCO") which provides LIPA with an option (the "2006 Purchase Option"), exercisable not later than December 31, 2006, to acquire the Barrett and Far Rockaway plants from GENCO. In the event that LIPA acquires either or both of such plants, LIPA and KeySpan have agreed that KeySpan, acting through a subsidiary to be designated, will operate and maintain such plants.

Such agreements are subject to approval by the New York State Comptroller and, as to form, by the New York State Attorney General and are also subject to the condition that each of the 2006 Settlement Agreement, the 2006 Option Agreement and the amendment to the Management Services Agreement must become effective or none will become effective. If such agreements become effective, the GPRA Option will expire. However, if such agreements do not become effective, the Authority will have 90 days to exercise the GPRA Option.

On February 27, 2006 KeySpan announced a definitive agreement under which KeySpan would be acquired in early 2007 by an affiliate of National Grid plc, a company organized under the laws of Great Britain. The transaction is subject to the approval of the shareholders of both companies and to various regulatory approvals. The Authority will evaluate the acquisition of KeySpan by National Grid plc and its effect on the Authority's agreements with KeySpan and the potential benefits to LIPA's customers of the acquisition. In the event there is a change of control of KeySpan, the Authority and LIPA have the option of canceling their contracts with KeySpan and the KeySpan Subs.

2006 Bond Issuance In March 2006, the Authority issued Series 2006A Electronic System Revenue Bonds totaling approximately $853 million to refund certain outstanding debt and 2006B Electronic System Revenue Bonds totaling approximately $97 million to reimburse LIPA's treasury for or to fund capital expenditures for system improvements. In addition, the Authority plans to remarket it Series 8F Subordinated Bonds in April 2006.

57

KPMG LLP Suite 200 1305 Walt Whitman Road Melville, NY 11747-4302 Report on Internal Control over Financial Reporting and on Compliance and Other Matters Based on an Audit of Financial Statements Performed in Accordance with Government Auditing Standards The Board of Trustees Long Island Power Authority:

We have audited the basic financial statements of the Long Island Power Authority (Authority) as of and for the year ended December 31, 2005, and have issued our report thereon dated March 23, 2006. We conducted our audit in accordance with auditing standards generally accepted in the United States of America and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States.

Internal Control over Financial Reporting In planning and performing our audit, we considered the Authority's internal control over financial reporting in order to determine our auditing procedures for the purpose of expressing our opinion on the basic financial statements and not to provide assurance on the internal control over financial reporting.

Our consideration of the internal control over financial reporting would not necessarily disclose all matters in the internal control over financial reporting that might be material weaknesses. A material weakness is a reportable condition in which the design or operation of one or more of the internal control components does not reduce to a relatively low level the risk that misstatements caused by error or fraud in amounts that would be material in relation to the financial statements being audited may occur and not be detected within a timely period by employees in the normal course of performing their assigned functions. We noted no matters involving the internal control over financial reporting and its operation that we consider to be material weaknesses.

Compliance and Other Matters As part of obtaining reasonable assurance about whether the Authority's basic financial statements are free of material misstatement, we performed tests of its compliance with certain provisions of laws, regulations, contracts and grant agreements, noncompliance with which could have a direct and material effect on the determination of financial statement amounts. However, providing an opinion on compliance with those provisions was not an objective of our audit and, accordingly, we do not express such an opinion. The results of our tests disclosed no instances of noncompliance or other matters that are required to be reported under GovernmentAuditing Standards.

This report is intended solely for the information and use of Authority management, the Authority's Board of Trustees, the New York State Division of the Budget and the New York State Office of the State Comptroller and is not intended to be and should not be used by anyone other than those specified parties.

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