UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 33-83618

SELKIRK COGEN PARTNERS, L.P.

SELKIRK COGEN FUNDING CORPORATION

7600 Wisconsin Avenue, Bethesda, Maryland 20814
(Address of principal executive offices, including zip code)

(301) 280-6800
(Registrants’ telephone number, including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12 (b) OR 12 (g) OF THE ACT:
None

     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 (or for such shorter period that the Registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes [X] No [   ]

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

     Indicate by check mark whether the registrants are accelerated filers (as defined in Exchange Act Rule 12b-2). Yes [   ] No [X]

     As of March 26, 2004, there were 10 shares of common stock of Selkirk Cogen Funding Corporation, $1 par value, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:
None

TABLE OF CONTENTS

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PART I

ITEM 1. BUSINESS

Business Overview and Structure

     Selkirk Cogen Partners, L.P. (the “Partnership”) is a Delaware limited partnership that owns a natural gas-fired cogeneration facility in the Town of Bethlehem, County of Albany, New York (together with associated materials, ancillary structures and related contractual and property interests, the “Facility”). The Partnership was formed in 1989, and its sole business is the ownership, operation and maintenance of the Facility. The Partnership has long-term contracts for the sale of electric capacity and energy produced by the Facility with Niagara Mohawk Power Corporation (“Niagara Mohawk”) and Consolidated Edison Company of New York, Inc. (“Con Edison”) and steam produced by the Facility with GE Plastics, a core business of General Electric Company (“General Electric”). The Partnership operates as a single business segment.

     Selkirk Cogen Funding Corporation (the “Funding Corporation”), a wholly owned subsidiary of the Partnership, was organized in April 1994 as a Delaware corporation to serve as a single-purpose financing subsidiary of the Partnership. All of the issued and outstanding capital stock of the Funding Corporation is owned by the Partnership.

     The Partnership and the Funding Corporation’s principal executive offices are located at 7600 Wisconsin Avenue, Bethesda, Maryland 20814. The telephone number is (301) 280-6800.

The Partnership

     The managing general partner of the Partnership is JMC Selkirk, Inc. (“JMC Selkirk” or the “Managing General Partner”). The other general partner of the Partnership (together with JMC Selkirk, the “General Partners”) is RCM Selkirk GP, Inc. (“RCM Selkirk GP”). The limited partners of the Partnership (the “Limited Partners,” and together with the General Partners, the “Partners”) are JMC Selkirk, PentaGen Investors, L.P. (“Investors”), Teton Selkirk, LLC (“Teton Selkirk”, formerly Aquila Selkirk, Inc.) and RCM Selkirk, L.P. (“RCM Selkirk LP”).

     The Managing General Partner is responsible for managing and controlling the business and affairs of the Partnership, subject to certain powers which are vested in the management committee of the Partnership (the “Management Committee”) under the Partnership Agreement. Each General Partner has a voting representative on the Management Committee, which, subject to certain limited exceptions, acts by unanimity. Thus, the General Partners, and principally the Managing General Partner, exercise control over the Partnership. JMCS I Management, Inc. (“JMCS I Management”), an affiliate of the Managing General Partner, is acting as the project management firm (the “Project

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Management Firm”) for the Partnership, and as such is responsible for the implementation and administration of the Partnership’s business under the direction of the Managing General Partner. Upon the occurrence of certain events specified in the Partnership Agreement, RCM Selkirk GP may assume the powers and responsibilities of the Managing General Partner and of the Project Management Firm. Under the Partnership Agreement, each General Partner other than the Managing General Partner may convert its general partnership interest to that of a Limited Partner.

     JMC Selkirk is an indirect, wholly owned subsidiary of Beale Generating Company (“Beale”), which is jointly owned by Cogentrix Eastern America, Inc. (“Cogentrix”) and National Energy Power Company, LLC (formerly PG&E Generating Power Group, LLC). Cogentrix is a subsidiary of Cogentrix Energy, Inc., an indirect, wholly owned subsidiary of Goldman Sachs Group, Inc. National Energy Power Company, LLC is a direct, wholly owned subsidiary of NEGT Energy Company, LLC (formerly PG&E Generating Company, LLC ), an indirect, wholly owned subsidiary of National Energy & Gas Transmission, Inc. (“NEGT”, formerly PG&E National Energy Group, Inc.). NEGT is an indirect subsidiary of PG&E Corporation.

     JMCS I Management is a direct, wholly owned subsidiary of National Energy Power Company, LLC. Previously, JMCS I Management was a direct, wholly owned subsidiary of National Energy Generating Services, LLC (formerly PG&E Generating Services, LLC), a direct, wholly owned subsidiary of NEGT Energy Company, LLC.

     Investors is a Delaware limited partnership consisting of JMCS I Holdings, Inc., JMC Selkirk (each an affiliate of Beale), and FPP Selkirk LLC (“FPP Selkirk”).

     RCM Selkirk GP and RCM Selkirk LP are beneficially owned by Robert C. McNair and members of his family (“RCM”).

     Teton Selkirk is a wholly owned subsidiary of Teton East Coast Generation, LLC (“Teton ECG”, formerly Aquila East Coast Generation, Inc.) which is a wholly owned subsidiary of Teton Power Funding LLC (“Teton Funding”, formerly MEP Investments, LLC). Teton Funding and FPP Selkirk share common indirect beneficial ownership.

The Funding Corporation

     The Funding Corporation was established for the sole purpose of issuing $165,000,000 of 8.65% First Mortgage Bonds Due 2007 (the “Old 2007 Bonds”) and $227,000,000 of 8.98% First Mortgage Bonds Due 2012 (the “Old 2012 Bonds,” and collectively with the Old 2007 Bonds, the “Old Bonds”) and as agent acting on behalf of the Partnership pursuant to a Trust Indenture among Funding Corporation, the Partnership and Bankers Trust Company, as trustee (the “Indenture”). A portion of the proceeds from the sale of the Old Bonds was loaned to the Partnership in connection with the financing of its outstanding indebtedness and the remaining proceeds were loaned to the Partnership (the total amount of such extensions of credit, the “Partnership Loans”). In November 1994, the Funding Corporation and the Partnership offered to exchange (i) $165,000,000 of 8.65% First

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Mortgage Bonds Due 2007, Series A (the “New 2007 Bonds”) for a like principal amount of Old 2007 Bonds, and (ii) $227,000,000 of 8.98% First Mortgage Bonds Due 2012, Series A (the “New 2012 Bonds,” and collectively with the New 2007 Bonds, the “New Bonds”, and the New Bonds together with the Old Bonds, the “Bonds”) for a like principal amount of Old 2012 Bonds, respectively, with the holders thereof. On December 12, 1994, the exchange of all of the Old Bonds for the New Bonds was completed, and none of the Old Bonds remain outstanding. The obligations of the Funding Corporation in respect of the Bonds are unconditionally guaranteed by the Partnership (the “Guarantee”).

     The Bonds, the Partnership Loans and the Guarantee are not guaranteed by, or otherwise obligations of, the Partners, Beale, FPP Selkirk, NEGT, Cogentrix Energy, Inc., RCM, Teton Funding, or any of their respective affiliates, other than the Funding Corporation and the Partnership. The obligations of the Partnership under the Partnership Loans and the Guarantee are secured by, among other things, a pledge by the General Partners of their respective general partnership interests in the Partnership and pledges by the shareholders of JMC Selkirk and RCM Selkirk GP of the outstanding capital stock of each such General Partner.

Relationship with NEGT

     NEGT owns an indirect interest in the Partnership, and through its indirect subsidiaries, JMC Selkirk and JMCS I Management, manages the Partnership. On July 8, 2003, NEGT and certain subsidiaries voluntarily filed petitions for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (collectively, the “NEGT Bankruptcy”) in the Greenbelt Division of the United States Bankruptcy Court for the District of Maryland (the “Bankruptcy Court”). The subsidiaries that filed voluntarily petitions and were disclosed in previous reports as related parties of the Partnership with which it engaged in transactions are: NEGT Energy Trading-Power, L.P. (“NEGT Energy Trading-Power”, formerly PG&E Energy Trading-Power, L.P.) and NEGT Energy Trading—Gas Corporation (“NEGT Energy Trading-Gas”, formerly PG&E Energy Trading-Gas Corporation). There were no amounts due to or from these subsidiaries at December 31, 2003.

     None of the Partnership or its NEGT affiliated partners (JMC Selkirk and Investors) are parties to the NEGT Bankruptcy. The Managing General Partner believes that JMC Selkirk, Investors, and the Partnership will not be substantively consolidated with NEGT in any bankruptcy proceeding involving NEGT, and that the NEGT Bankruptcy will not have a material adverse impact on the Partnership’s operations.

     However, the Partnership cannot be certain that the NEGT Bankruptcy will not affect NEGT’s arrangements with respect to the Partnership or the ability of JMC Selkirk or JMCS I Management to manage the Partnership. The Partnership Agreement provides certain management rights to RCM Selkirk GP in the event that JMC Selkirk were to be included as a debtor within the NEGT Bankruptcy, or either JMC Selkirk or JMCS I Management were to be in material default of its obligations to the Partnership (following notice and a 120 day cure period). These protections (the “Special Management Rights”) include (i) the removal of JMC Selkirk as the managing general partner, (ii) the appointment of itself as the successor managing general partner, and (iii) the termination of the administrative services agreement with JMCS I Management and subsequent appointment of a RCM Selkirk GP affiliate as the project management firm. Enforcement of these rights by RCM Selkirk GP could, however, be delayed or impeded as a result of any bankruptcy proceeding involving JMC Selkirk. Moreover, the bankruptcy of any partner of the Partnership would be an event of default under the Partnership’s Credit Agreement. (See “Credit Agreement”, included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations below)

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     On February 26, 2004, NEGT filed with the Bankruptcy Court its Third Amended Plan of Reorganization and the related Disclosure Statement (the “POR”). The POR contemplates that, unless NEGT sells its power generation and pipeline businesses as described in the POR, it will retain and continue to operate these businesses, separate from PG&E Corporation, and will issue new debt securities and common stock. NEGT’s indirect ownership interest in the general partner interest of JMC Selkirk and the limited partner interests of JMC Selkirk and Investors in the Partnership are included within its power generation business. The Partnership cannot predict whether a sale by NEGT of its interest in the Partnership (a “NEGT Interest Sale”) will be completed. Any NEGT Interest Sale may affect JMCS I Management’s administrative services contract with the Partnership. Further, if a NEGT Interest Sale were to be completed, the ability of JMC Selkirk or JMCS I Management to manage the Partnership may be adversely affected, in which event RCM Selkirk GP may be entitled to exercise the Special Management Rights set forth in the Partnership Agreement.

The Facility and Certain Project Contracts

The Facility

     The Facility is located on a 15.7 acre site leased from General Electric adjacent to General Electric’s plastic manufacturing plant (the “GE Plant”) in the Town of Bethlehem, County of Albany, New York (the “Facility Site”). The Facility is a natural gas-fired cogeneration facility, which has a total electric generating capacity in excess of 345 megawatts (“MW”) with a maximum average steam output of 400,000 pounds per hour (“lbs/hr”). The Facility consists of one unit (“Unit 1”) with an electric generating capacity of approximately 79.9 MW and a second unit (“Unit 2”) with an electric generating capacity of approximately 265 MW. The Public Utilities Regulatory Policies Act of 1978, as amended (“PURPA”) defines a cogeneration facility as a facility which produces electric energy and forms of useful thermal energy (such as heat or steam), used for industrial, commercial, heating or cooling purposes, through the sequential use of one or more energy inputs. In the case of the Facility, the Facility uses natural gas as its primary fuel input to produce electric energy for sale to Niagara Mohawk, Con Edison, and the New York Independent System Operator (“NY ISO”) and to produce useful thermal energy in the form of steam for sale to General Electric for industrial purposes. The Facility is a “topping-cycle cogeneration facility,” which means that when the Facility is operated in a combined-cycle mode, it uses natural gas or fuel oil to produce electricity, and the reject heat from power production is then used to provide steam to General Electric. Unit 1 and Unit 2 have been designed to operate independently for electrical generation, while thermally integrated for steam generation,

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thereby optimizing efficiencies in the combined performance of the Facility. A properly designed and constructed cogeneration facility is able to convert the energy contained in the input fuel source to useful energy outputs more efficiently than typical utility plants. The Facility has been certified as a qualifying facility (“Qualifying Facility”) in accordance with PURPA and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (“FERC”).

Niagara Mohawk

     The Partnership has a long-term contract with Niagara Mohawk for the sale of electric capacity and energy produced by Unit 1 to Niagara Mohawk. Electric sales to Niagara Mohawk for the year ended December 31, 2003 accounted for 15.9% of total project revenues, compared to 15.3% in 2002 and 16.5% in 2001.

     Unit 1 commenced commercial operation on April 17, 1992 and through June 30, 1998 sold at least 79.9 MW of electric capacity and associated energy to Niagara Mohawk under the original long-term contract that allowed Niagara Mohawk to schedule Unit 1 for dispatch on an economic basis (the “Original Niagara Mohawk Power Purchase Agreement”). The term of the Original Niagara Mohawk Power Purchase Agreement was 20 years from the date of initial commercial operation of Unit 1. On August 31, 1998 the Partnership and Niagara Mohawk executed an Amended and Restated Power Purchase Agreement dated as of July 1, 1998 (the “Amended and Restated Niagara Mohawk Power Purchase Agreement”). The term of the Amended and Restated Niagara Mohawk Power Purchase Agreement is ten years from July 1, 1998 (with the exception of certain transitional call and put rights which were held by Niagara Mohawk and the Partnership (the “Transitional Rights”) and terminated on October 31, 2000, with respect to energy and capacity sales).

     The Amended and Restated Niagara Mohawk Power Purchase Agreement provides for a monthly contract payment (“Monthly Contract Payment”) which is comprised of four indexed pricing components: (i) a capacity payment, (ii) an energy payment, (iii) a transportation payment, and (iv) an operation and maintenance payment. The capacity payment, transportation payment, operation and maintenance payment and a fixed portion of the energy payment are payable whether or not the Partnership sells energy or capacity to Niagara Mohawk. The variable portion of the energy payment varies with the quantities of energy and capacity actually sold to Niagara Mohawk pursuant to the Transitional Rights or exercise by Niagara Mohawk of its right of first refusal described below. Niagara Mohawk will be obligated to pay the Partnership the Monthly Contract Payment to the extent such number is positive, and the Partnership will be obligated to pay Niagara Mohawk the Monthly Contract Payment to the extent such number is negative. Since the capacity payment and the fixed portion of the energy payment are offset by actual market prices, during periods in which the market energy price or market capacity price is high, the sum of these payments could result in a negative number. In such event the Partnership would be obligated to make payments to Niagara Mohawk. Under the Amended and Restated Niagara Mohawk Power Purchase Agreement, the Partnership at all times retains the right to sell Unit 1 energy and associated capacity at the prevailing market price (assuming the plant is available for generation). The Partnership would expect net revenues from such sales to

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mitigate the impact of any payments it might be required to make to Niagara Mohawk during periods in which actual market prices are high.

     During the period from July 1, 1998 through November 18, 1999, the initial market pricing for energy was a proxy market price based on Niagara Mohawk’s tariff for power purchases from Qualifying Facilities. On November 18, 1999, the NY ISO commenced operations for each of eleven regions and at each generator interconnection within New York State. The NY ISO establishes a marketplace whereby market prices will be determined based on daily bids for quantity and price of energy as put by each willing supplier and will establish the price at which each generator will be paid for energy supplied to the region.

     The Amended and Restated Niagara Mohawk Power Purchase Agreement transfers dispatch decision-making authority from Niagara Mohawk to the Partnership, whereby the Partnership will have the ability and flexibility to dispatch Unit 1 based on current market conditions. Niagara Mohawk has a right of first refusal to purchase energy and/or capacity up to the applicable monthly contract quantity during the ten-year term of the Amended and Restated Niagara Mohawk Power Purchase Agreement. Accordingly, before the Partnership may sell such energy and associated capacity to third parties, it must first offer Niagara Mohawk the opportunity to purchase that energy and capacity at the market energy price, and, if applicable, the market capacity price. If Niagara Mohawk declines, the Partnership may sell such power to third parties. Energy and associated capacity in excess of the monthly contract quantity is not subject to Niagara Mohawk’s right of first refusal.

     The annual contract volumes and notional contract quantities which are used to calculate the fixed portions of the Monthly Contract Payment and establish the maximum quantities of energy and capacity, which are subject to Niagara Mohawk’s right of first refusal, are set forth below.

     Niagara Mohawk owns, operates and maintains interconnection facilities for the combined Facility in accordance with separate Unit 1 and Unit 2 interconnection agreements. The Unit 1 interconnection facility is necessary to effect the transfer of electricity produced at Unit 1 into Niagara Mohawk’s power grid at the delivery point adjacent to Unit 1. Since Unit 1 is interconnected directly to the power grid, no transmission services are required for the

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delivery of power directly to the NY ISO. The Unit 2 interconnection facility is necessary to effect the transfer of electricity produced at Unit 2 into Niagara Mohawk’s transmission system. Pursuant to a transmission services agreement, Niagara Mohawk has agreed to provide firm transmission services from Unit 2 to the point of interconnection between Niagara Mohawk’s transmission system and Con Edison’s transmission system for a period of 20 years from the date of the commencement of commercial operation of Unit 2.

Con Edison

     Unit 2 commenced commercial operation on September 1, 1994 and is selling 265 MW of electric capacity and associated energy to Con Edison under a long-term contract that allows Con Edison to schedule Unit 2 for dispatch on an economic basis (the “Con Edison Power Purchase Agreement,” and together with the Amended and Restated Niagara Mohawk Power Purchase Agreement, the “Power Purchase Agreements”). The Con Edison Power Purchase Agreement has a term of 20 years from the date of commencement of commercial operation of Unit 2, subject to a 10-year extension under certain conditions. The Con Edison Power Purchase Agreement provides for four payment components: (i) a capacity payment, (ii) a fuel payment, (iii) an Operations and Maintenance (“O&M”) payment and (iv) a wheeling payment. The capacity payment, a portion of the fuel payment, a portion of the O&M payment, and the wheeling payment are fixed charges to be paid on the basis of plant availability to operate whether or not Unit 2 is dispatched on-line. The variable portions of the fuel payment and O&M payment are payable based on the amount of electricity produced by Unit 2 and delivered to Con Edison. The total fixed and variable fuel payment is capped at a ceiling price established (and is subject to adjustment) in accordance with the Con Edison Power Purchase Agreement, and includes a component, which is equal to one-half of the amount by which Unit 2’s actual fixed and variable fuel commodity and transportation costs differs from the ceiling price. Electric sales to Con Edison for the year ended December 31, 2003 accounted for 64.6% of total project revenues, compared to 63.0% in 2002 and 65.2% in 2001.

New York Independent System Operator

     The NY ISO commenced operation on November 18, 1999 and took formal control of the New York wholesale electric power system on December 1, 1999. The NY ISO administers markets in energy, installed capacity and ancillary services for the New York control area and operates the bulk power transmission system in New York. Energy transactions in New York may involve sales and purchases to and from the NY ISO in the NY ISO-administered markets, or bilateral transactions between participants in the New York wholesale market. The Partnership is an active participant in these markets. To enter into energy transactions with the NY ISO, the Partnership entered into a services agreement under the New York ISO Market Administration and Control Services Tariff (the “Services Agreement”) with the NY ISO on October 12, 1999. Sales to the NY ISO for the year ended December 31, 2003 accounted for 13.1% of total project revenues, compared to 11.0% in 2002 and 8.1% in 2001.

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NEGT Energy Trading-Power

     During the period May 31, 1996 through May 31, 2003, the Partnership had an enabling agreement (the “Enabling Agreement”) with NEGT Energy Trading–Power, an indirect, wholly owned subsidiary of NEGT and an affiliate of JMC Selkirk. Through the Enabling Agreement, the Partnership could sell excess capacity and energy generated from Units 1 and 2 and other energy-related products to NEGT Energy Trading–Power. As of May 31, 2003, the Partnership ceased transactions with NEGT Energy Trading–Power. There were no sales of energy, capacity and other services pursuant to this enabling agreement for the year ended December 31, 2003, compared to 1.0% of total project revenues in 2002 and 1.9% in 2001.

General Electric

     Pursuant to a steam sales agreement with General Electric (the “Steam Sales Agreement”), the Partnership is obligated to sell up to 400,000 lbs/hr of the thermal output of Unit 1 and Unit 2 for use as process steam at the GE Plant adjacent to the Facility for a term extending 20 years from the date of commercial operations of Unit 2. The Partnership charges General Electric a nominal price for steam delivered to General Electric in an amount up to the annual equivalent of 160,000 lbs/hr during each hour in which the GE Plant is in production (the “Discounted Quantity”). Steam sales in excess of the Discounted Quantity are priced at General Electric’s avoided variable direct cost, subject to an “annual true-up” to ensure that General Electric receives the annual equivalent of the Discounted Quantity at nominal pricing.

     Pursuant to the Steam Sales Agreement, General Electric may implement productivity or energy efficiency projects in its manufacturing processes, including projects involving the production of steam within the GE Plant commencing in 1996. General Electric implemented an energy efficiency project in 1997 that reduced the quantity of steam required by the GE Plant. Under the energy efficiency project, General Electric anticipates managing its annual average steam demand at 160,000 lbs/hr. If General Electric is able to manage its annual average steam demand at 160,000 lbs/hr then the Partnership’s steam revenues would be reduced to the nominal amount General Electric is charged for the annual equivalent of 160,000 lbs/hr. The energy efficiency project does not relieve General Electric of its contractual obligation to purchase the minimum thermal output necessary for the Facility to maintain its status as a Qualifying Facility. Sales to General Electric for the year ended December 31, 2003 accounted for 0.0% of total project revenues, compared to 0.1% in 2002 and 0.0% in 2001.

Unit 1 Gas Supply and Transportation

     To supply natural gas needed to operate Unit 1, the Partnership entered into a gas supply agreement with Paramount Resources Ltd. (“Paramount”) on a firm 365-day per year basis for a 15-year term beginning November 1, 1992 (the “Original Paramount Contract”). On May 6, 1998, the Partnership and Paramount executed a Second Amended and Restated Gas Purchase Contract (the “Amended Paramount Contract”) in conjunction with

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consummation of the transactions pursuant to the Amended and Restated Niagara Mohawk Power Purchase Agreement. Under the Amended Paramount Contract, the 15-year term remains unchanged, and the maximum daily quantity of natural gas that the Partnership is entitled to purchase is 16,400 Mcf. The Amended Paramount Contract requires Paramount to maintain a level of recoverable reserves and deliverability from its dedicated reserves through the term of the Amended Paramount Contract. Paramount must demonstrate that it meets the recoverable reserves and deliverability requirements in an annual report to the Partnership.

     The Partnership entered into certain long-term contracts (collectively, the “Unit 1 Gas Transportation Contracts”) for the transportation of the Unit 1 natural gas volumes on a firm 365-day per year basis with TransCanada Pipelines Limited (“TransCanada”), Iroquois Gas Transmissions System, L.P. (“Iroquois”) and Tennessee Gas Pipeline Company (“Tennessee”). Each of the Unit 1 Gas Transportation Contracts has a term of 20 years beginning November 1, 1992. Concurrent with the effectiveness of the Amended Paramount Contract, the Partnership released 6,000 Mcf of the Partnership’s daily transportation capacity rights under the Partnership’s firm gas transportation contract for Unit 1 with TransCanada, in conjunction with Paramount’s acquiring 6,000 Mcf of daily transportation capacity rights on TransCanada’s pipeline system.

Unit 2 Gas Supply and Transportation

     To supply natural gas needed to operate Unit 2, the Partnership entered into gas supply agreements with Imperial Oil Resources, EnCana Gas Marketing (formerly PanCanadian Petroleum Limited) and Producers Marketing Ltd. (formerly Atcor Limited) (collectively, the “Unit 2 Gas Supply Contracts”), each on a firm 365-day per year basis. Each of the Unit 2 Gas Supply Contracts has a 15-year term beginning November 1, 1994. The Unit 2 gas suppliers have supported their delivery obligations to the Partnership with their respective corporate warranties. The Unit 2 Gas Supply Contracts are not supported by dedicated reserves. The Partnership entered into certain long-term contracts (collectively, the “Unit 2 Gas Transportation Contracts”) for the transportation of the Unit 2 natural gas volumes on a firm 365-day per year basis with TransCanada, Iroquois and Tennessee. Each of the Unit 2 Gas Transportation Contracts has a term of 20 years beginning November 1, 1994.

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Fuel Management

     The Partnership directs the supply and transportation of natural gas to Unit 1 and Unit 2 under its long-term gas supply and transportation contracts so as to have sufficient quantities of natural gas available at the Facility to meet its scheduled operation. In addition, the Partnership may enter into short-term transactions to resell its long-term, firm natural gas volumes at favorable prices relative to their costs and relative to the cost of substitute fuels. These transactions include “gas resales”, “gas transportation optimizations” and “peak shaving arrangements”. Gas resales are sales of excess natural gas supplies when Unit 1 or Unit 2 is dispatched off-line or at less than full capacity. Gas transportation optimizations are transactions whereby the Partnership is able to optimize the long-term gas transportation contracts and lower the cost of natural gas delivered to the Facility by purchasing and/or selling natural gas at favorable prices along the transportation route. Peak shaving arrangements are transactions whereby the Partnership grants to local distribution companies or other purchasers a call on a specified portion of the Partnership’s firm natural gas supply for a specified number of days during the winter season. At such times as the purchaser calls upon the Partnership’s firm natural gas supply under a peak shaving arrangement, the Partnership intends to operate on spot market natural gas supplies utilizing the Partnership’s firm gas transportation. Typically, the Partnership’s liability for failure to deliver natural gas when called for under a peak shaving agreement is to reimburse the purchaser for its prudently incurred incremental costs of finding a replacement supply of natural gas. The Partnership attempts to schedule firm gas transportation services to meet its requirements to fuel Unit 1 and Unit 2 and to meet its gas resales, gas transportation optimizations and peak shaving sales commitments without incurring penalties for taking natural gas above or below amounts nominated for delivery from the gas transporters. The Partnership supplements its contracted firm transportation to the extent necessary to make gas resales, gas transportation optimizations and peak shaving sales by entering into agreements for interruptible transportation service. In managing Unit 2’s fuel arrangements, the Partnership intends to take into account that the Partnership must purchase a minimum annual quantity of natural gas under the Unit 2 Gas Supply Contracts, subject to true-up procedures, to avoid reduction of the maximum daily contract quantity under such agreements. Fuel revenues, accounted for 6.4% of total project revenues for the year ended December 31, 2003, compared to 9.6% in 2002 and 8.3% in 2001. Approximately half of the fuel revenues for year ended December 31, 2003 and the majority of fuel revenues for the years ended December 31, 2002 and 2001, resulted from sales with NEGT Energy Trading–Gas, an indirect, wholly owned subsidiary of NEGT and an affiliate of JMC Selkirk. As of May 31, 2003, the Partnership ceased transactions with NEGT Energy Trading-Gas. The Partnership believes there are sufficient counterparties available with which to undertake transactions in the natural gas market and therefore, the Partnership’s cessation of transactions with NEGT Energy Trading-Gas will not have a material impact on the results of operations of the Partnership.

     Unit 1 and Unit 2 have the equipment to operate on No. 2 fuel oil and are designed to switch fuel sources from natural gas to fuel oil, and back, without interrupting the generation of electricity. The Partnership’s air permit allows the Facility to burn oil for a maximum of 2,190 hours per year (91.25 days per year) at full capacity. The Partnership currently has on-site storage for approximately 910 thousand gallons of fuel oil, a supply sufficient to run all

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three gas turbines constituting the Facility for approximately one and a half days at full capacity without refilling.

Customers/Competition

     Niagara Mohawk is an investor-owned utility engaged in the purchase, transmission and distribution of electrical energy and natural gas to customers in upstate New York.

     Con Edison is an investor-owned utility engaged in the purchase and/or production, transmission and distribution of electrical energy and natural gas to New York City (except portions of Queens) and most of Westchester County, New York.

     The NY ISO is a not-for-profit organization that has the objective of facilitating fair and open competition in the wholesale power market and creating an electricity commodity market in which power is purchased and sold on the basis of competitive bidding.

     GE Plastics, a core business of General Electric, manufactures high-performance engineered plastics used in applications such as automobiles, housings for computers and other business equipment. GE Plastics sells worldwide to a diverse customer base consisting mainly of manufacturers.

     The Partnership also conducts business with other customers in the energy industry, such as investor-owned utilities, energy trading companies, financial institutions, gas production companies and gas transportation companies located in the United States and Canada.

     The demand for power in the United States traditionally has been met by utility construction of large-scale electric generation projects under rate-base regulation. PURPA removed certain regulatory constraints relating to the production and sale of electric energy by eligible non-utilities and required electric utilities to buy electricity from various types of non-utility power producers under certain conditions, thereby encouraging companies other than electric utilities to enter the electric power production market. Concurrently, there has been a decline in the construction of large generating plants by electric utilities. In addition to independent power producers, subsidiaries of fuel supply companies, engineering companies, equipment manufacturers and other industrial companies, as well as subsidiaries of regulated utilities, have entered the non-utility power market. The Partnership has a long-term agreement to sell electric generating capacity and energy from the Facility to Con Edison. The Partnership has also executed an Amended and Restated Power Purchase Agreement with Niagara Mohawk, which now provides a hedge on energy costs to Niagara Mohawk while also providing for the Partnership’s recovery of capacity and other fixed payments over a term of ten years. Therefore, the Partnership does not expect competitive forces to have a significant effect on this portion of its business. Nevertheless, the Facility will typically be scheduled on an economic basis, which takes into account the variable cost of electricity to be delivered by each unit compared to the variable cost of electricity available to the purchaser from other sources. Accordingly, competitive forces may have some effect on the Facility’s dispatch levels. The Partnership cannot, at this time, determine what long-term effect, if any, the impact of such competitive sales will have on the Partnership’s financial condition or

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results of operation. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of the Facility’s dispatch levels.

Seasonality

     The Partnership’s reliance on its power purchasers’ customer and market demand results in the Facility’s dispatch being somewhat affected by seasonality. Electric markets typically peak during the warmer summer months due to customer reliance on air conditioning and again during the darker winter months as customers utilize more lighting. In addition, the gas resale market is also somewhat seasonal in nature, with the cold winter months tending to drive up the price of natural gas.

Regulations and Environmental Matters

     The Partnership must sell an aggregate annual average of approximately 80,000 lbs/hr from Unit 1 and Unit 2 combined for use as process steam by General Electric and must satisfy other operating and ownership criteria in order to comply with the requirements for a Qualifying Facility under PURPA. If the Facility were to fail to meet such criteria, the Partnership may become subject to regulation as a subsidiary of a holding company, a public utility company or an electric utility company under PUHCA, the Federal Power Act (the “FPA”) and state utility laws. If the Facility loses its Qualifying Facility status, its Power Purchase Agreements will be subject to the jurisdiction of the FERC under the FPA. The Partnership may nevertheless be exempt from regulation under PUHCA if it maintains “exempt wholesale generator” status. In 1994, the Partnership filed with the FERC an Application for Determination of Exempt Wholesale Generator Status, which was granted by the FERC.

     In addition to being a Qualifying Facility, Unit 1, prior to the commencement of operations by Unit 2, was a New York State co-generation facility under the New York Public Service Law and consequently exempt from most regulation otherwise applicable under that law to Unit 1’s steam and electric operations. The Partnership has obtained from the NYPSC a declaratory order that the Facility will not be subject to regulation as an electric corporation, steam corporation or gas corporation under the New York Public Service Law, except to the extent necessary to implement safety and environmental regulation. Under certain circumstances, and subject to the conditions set forth in the Indenture, the Partnership may become subject to regulation under the New York Public Service Law as an electric corporation, steam corporation or gas corporation. For example, if the Partnership were to engage in sales of electricity to General Electric at the GE Plant, the Partnership could be deemed an electric corporation.

     All regulatory approvals currently required to operate the combined Facility have been obtained. In response to regulatory change, and in the course of normal business, the Partnership files requisite documents and applies for a variety of permits, modifications, renewals and regulatory extensions. It is not possible to ascertain with certainty when or if the various required governmental approvals and actions which are petitioned will be

12

accomplished, whether modifications of the Facility will be required or, generally, what effect existing or future statutory action may have upon Partnership operations.

     The Partnership is subject to federal, state, and local laws and regulations pertaining to air and water quality, and other environmental matters. Except as set forth herein below, no material proceedings have been commenced or, to the knowledge of the Partnership, are contemplated by any federal, state or local agency against the Partnership, nor is the Partnership a defendant in any litigation with respect to any matter relating to the protection of the environment.

     The 1990 amendments to the Federal Clean Air Act (the “1990 Clean Air Amendments”) require a large number of rulemaking and other actions by the United States Environmental Protection Agency (the “EPA” or the “Agency”) and the New York State Department of Environmental Conservation (the “DEC”). The DEC has adopted regulations for New York State’s (the “State”) operating permit program consistent with the requirements of Title V of the 1990 Clean Air Act Amendments and has received interim final approval of the State’s program from the EPA. Pursuant to the State’s program the Facility is required to obtain a new Title V operating permit, an application for which was submitted to the DEC prior to June 9, 1997.

     On November 6, 2001, the Partnership received from the DEC the Facility’s Title V operating permit endorsed by the DEC on November 2, 2001 (the “Title V Permit”). The Title V Permit as received by the Partnership contains conditions that conflict with the Partnership’s existing air permits, and the Facility’s compliance with these conditions under certain operating circumstances would be problematic. Further, the Partnership believes that certain of the conditions contained in the Title V Permit are inconsistent with the laws and regulations underlying the Title V program and Title V operating permits issued by the DEC to comparable electric generating facilities in New York. By letter dated November 12, 2001, the Partnership has filed with the DEC a request for an adjudicatory hearing to address and resolve the issues presented by the Title V Permit. The DEC has confirmed that the terms and conditions of the Title V Permit are stayed pending a final DEC decision on the appeal. Since November 12, 2001, the Partnership and DEC staff have engaged in negotiations regarding the Title V Permit. At this time, the Partnership cannot assess whether a settlement can be achieved, the likely outcome of the adjudicatory hearing if no settlement is achieved, or the impact on the Facility.

Employees

     The Partnership has no employees. The Project Management Firm provides overall management and administration services to the Partnership pursuant to a Project Administrative Services Agreement. The Project Management Firm provides eight employees at the Facility and support personnel from its Bethesda, Maryland and Boston, Massachusetts offices.

     General Electric through its O&M services component (the “Operator”) provides operation and maintenance services for the Facility pursuant to a Second Amended and

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Restated Operation and Maintenance Agreement between the Partnership and General Electric (the “O&M Agreement”). The Operator has substantial experience in operating and maintaining generating facilities using combustion turbine and combined cycle technology and provides 29 employees to operate the Facility.

ITEM 2. PROPERTIES

     The Facility is located in the Town of Bethlehem, County of Albany, New York, on approximately 15.7 acres of land, which is leased by the Partnership from General Electric. In addition, the Partnership laterally owns an approximately 2.1 mile pipeline that is used for the transportation of natural gas from a point of interconnection with Tennessee’s pipeline facilities to the Facility Site. General Electric has granted certain permanent easements for the location of certain of the Unit 1 and Unit 2 interconnection facilities and other structures.

     The Partnership has leased the Facility to the Town of Bethlehem Industrial Development Agency (the “IDA”) pursuant to a facility lease agreement. The IDA has leased the Facility back to the Partnership pursuant to a sublease agreement. The IDA’s participation exempts the Partnership from certain mortgage recording taxes, certain state and local real property taxes and certain sales and use taxes within New York State.

ITEM 3. LEGAL PROCEEDINGS

     As part of the ordinary course of business, the Partnership routinely files complaints and intervenes in rate proceedings filed with the FERC by its gas transporters, as well as related proceedings.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

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PART II

ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

     There is no established public market for Funding Corporation’s common stock. The ten issued and outstanding shares of common stock of Funding Corporation, $1.00 par value per share, are owned by the Partnership. All of the common equity interests of the Partnership are held by the Partners and, therefore, there is no established public market for the Partnership’s common equity interests.

ITEM 6. SELECTED FINANCIAL DATA

     The following tables present a summary of the Partnership’s historical financial data and should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included herein.

Statement of Operations Data (in thousands):

Balance Sheet Data (in thousands):

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the information under “Item 1. Business” above, as well as the Partnership’s consolidated financial statements and notes to the accompanying consolidated financial statements included herein.

Cautionary Statement Regarding Forward-Looking Statements

     The information in this Annual Report on Form 10-K including this discussion and analysis contains forward-looking statements that are necessarily subject to various risks and uncertainties. Use of words like “anticipate,” “estimate,” “intend,” “project,” “plan,” “expect,” “will,” “believe,” “could,” and similar expressions help identify forward-looking statements and constitute forward-looking statements under the Private Securities Litigation Reform Act of 1995. These statements are based on current expectations and assumptions, which the Partnership believes are reasonable and on information currently available to the Partnership. Actual results could differ materially from those contemplated by the forward-looking statements. Although the Partnership believes that the expectations reflected in the forward-looking statements are reasonable, future results, events, levels of activity, performance or achievements cannot be guaranteed. Although the Partnership is not able to predict the more significant factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements or historical results include:

Operational Risks

     The Partnership’s future results of operation and financial condition will be affected by the performance of equipment; levels of dispatch; the receipt of certain capacity and other fixed payments; electricity prices; natural gas resale prices; fuel deliveries and prices; unanticipated changes in operating expenses or capital expenditures or other maintenance activities; variations in weather and natural disasters; and the potential impacts of threatened or actual terrorism and war.

Accounting and Risk Management

     The Partnership’s future results of operation and financial condition may be affected by the effect of new accounting pronouncements; changes in critical accounting policies or estimates; the effectiveness of the Partnership’s risk management policies and procedures; changes in the number of participants in the energy trading markets; the ability of the Partnership’s counterparties to satisfy their financial commitments to the Partnership and the impact of counterparties’ nonperformance on the Partnership’s liquidity position; and heightened rating agency criteria and the impact of changes in the Partnership’s credit ratings.

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Legislative and Regulatory Matters

     The Partnership’s business may be affected by legislative or regulatory changes affecting the electric and natural gas industries in the United States, including the pace and extent of efforts to restructure the electric and natural gas industries; heightened regulatory and enforcement agency focus on the energy business with the potential for changes in industry regulations and in the treatment of the Partnership by state and federal agencies; changes in or application of federal, state, and local laws and regulations to which the Partnership is subject including changes in corporate governance and securities laws requirements; and changes in or application of Canadian laws, regulations, and policies which may impact the Partnership.

Litigation and Environmental Matters

     The Partnership’s future results of operation and financial condition may be affected by the effect of compliance with existing and future environmental and safety laws, regulations, and policies, the cost of which could be significant; the outcome of future litigation and environmental matters; and the outcome of the negotiations with the DEC regarding the Facility’s Title V operating permit as described in “Regulations and Environmental Matters” below.

Business Description

     The Partnership owns a natural gas-fired, combined-cycle cogeneration facility consisting of two units designed to operate independently for electrical generation, but thermally integrated for steam generation. Revenues are derived primarily from sales of electricity and, to a lesser extent, from sales of steam and natural gas. The Partnership operates as a single business segment.

     The Partnership has long-term contracts for the sale of electric capacity and energy produced by the Facility with Niagara Mohawk and Con Edison. Under the Amended and Restated Niagara Mohawk Power Purchase Agreement, the Partnership has dispatch decision–making authority for Unit 1, whereby it has the ability and flexibility to operate the unit based on current market conditions. Under the Con Edison Power Purchase Agreement, Con Edison dispatches Unit 2 on an economic basis, whereby it takes into account the variable cost of electricity to be delivered by the unit compared to the variable cost of electricity available from other sources.

     The Partnership directs the supply and transportation of natural gas to Unit 1 and Unit 2 under its long-term gas supply and transportation agreements so as to have sufficient quantities of natural gas available at the Facility to meet its scheduled operation. In addition, the Partnership may enter into short-term transactions to resell its long-term, firm natural gas volumes at favorable prices relative to their costs and relative to the cost of substitute fuels. These transactions include “gas resales”, “gas transportation optimizations” and “peak shaving arrangements” (see “Item 1. Business: Fuel Management” above).

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     The Partnership determines when to schedule a unit off-line for major maintenance activities based upon equipment manufacturer guidelines, the actual condition of the unit based on maintenance experience, operating experience, and operating schedule. Taking into account these factors, coupled with current capacity factors, recent operating experience, and industry practice, scheduled major maintenance outages may be expected to occur approximately every three years. Differences in the timing and scope of scheduled maintenance can have a significant impact on revenues and the cost of revenues.

Executive Summary

     During 2003, the Partnership improved its financial results in a challenging climate consisting of volatile wholesale energy markets, credit quality deterioration of industry participants, and the slowing of the U.S. economy. The Partnership generated net income of $53.0 million and cash flows from operations of $64.4 million during 2003. The increase in earnings and cash flows from operations compared to 2003 was primarily due to higher electric revenues and lower maintenance expenses. The renewal of the Credit Agreement through August 2005, for a maximum credit amount of $10.0 million, allowed the Partnership to secure $2.9 million of collateral requirements with a letter of credit instead of cash flows from operations. At December 31, 2003, the Partnership had an additional $7.1 million available to be drawn under the Credit Agreement for working capital purposes.

     Electric market energy prices, the price of electric energy under the Partnership’s power purchase agreements, natural gas resale prices and the price of natural gas under the Partnership’s firm gas supply agreements were higher in 2003 as compared to 2002. During the first two months of 2004, these prices have been comparable to the same period in the prior year. The Partnership cannot predict whether such prices will remain comparable to 2003 levels for the balance of 2004.

     The Partnership has scheduled the Facility for five weeks of major maintenance outages during 2004, as compared to the five weeks of non-major maintenance outages experienced during 2003. Although the maintenance outages scheduled for 2004 are for the same duration as those experienced during 2003, the Partnership cannot predict electric and gas market conditions or the resulting impact on revenues during 2004. As a result of the expanded scope of the scheduled maintenance outages planned for 2004, the Partnership expects maintenance expenses to be higher in 2004 as compared to 2003. However, the Partnership does not expect the cost of major maintenance in 2004 to have a significant impact on cash flows used in operations, as the majority of these expenditures will be funded from the Major Maintenance Reserve Fund (see “Liquidity and Capital Resources -Funds” below).

Relationship with NEGT

     NEGT owns an indirect interest in the Partnership, and through its indirect subsidiaries, JMC Selkirk and JMCS I Management, manages the Partnership. On July 8, 2003, NEGT and certain subsidiaries voluntarily filed petitions for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (collectively, the “NEGT Bankruptcy”) in the Greenbelt Division of the United States Bankruptcy Court for the District of Maryland (the “Bankruptcy Court”). The subsidiaries that filed voluntarily petitions and were disclosed in previous reports as related parties of the Partnership with which it engaged in transactions are: NEGT Energy Trading-Power and NEGT Energy Trading—Gas. There were no amounts due to or from these subsidiaries at December 31, 2003.

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     None of the Partnership or its NEGT affiliated partners (JMC Selkirk and Investors) are parties to the NEGT Bankruptcy. The Managing General Partner believes that JMC Selkirk, Investors, and the Partnership will not be substantively consolidated with NEGT in any bankruptcy proceeding involving NEGT, and that the NEGT Bankruptcy will not have a material adverse impact on the Partnership’s operations.

     However, the Partnership cannot be certain that the NEGT Bankruptcy will not affect NEGT’s arrangements with respect to the Partnership or the ability of JMC Selkirk or JMCS I Management to manage the Partnership. The Partnership Agreement provides certain management rights to RCM Selkirk GP in the event that JMC Selkirk were to be included as a debtor within the NEGT Bankruptcy, or either JMC Selkirk or JMCS I Management were to be in material default of its obligations to the Partnership (following notice and a 120 day cure period). These protections (the “Special Management Rights”) include (i) the removal of JMC Selkirk as the managing general partner, (ii) the appointment of itself as the successor managing general partner, and (iii) the termination of the administrative services agreement with JMCS I Management and subsequent appointment of a RCM Selkirk GP affiliate as the project management firm. Enforcement of these rights by RCM Selkirk GP could, however, be delayed or impeded as a result of any bankruptcy proceeding involving JMC Selkirk. Moreover, the bankruptcy of any partner of the Partnership would be an event of default under the Partnership’s Credit Agreement. (See “Credit Agreement” below)

     On February 26, 2004, NEGT filed with the Bankruptcy Court its Third Amended Plan of Reorganization and the related Disclosure Statement (the “POR”). The POR contemplates that, unless NEGT sells its power generation and pipeline businesses as described in the POR, it will retain and continue to operate these businesses, separate from PG&E Corporation, and will issue new debt securities and common stock. NEGT’s indirect ownership interest in the general partner interest of JMC Selkirk and the limited partner interests of JMC Selkirk and Investors in the Partnership are included within its power generation business. The Partnership cannot predict whether a sale by NEGT of its interest in the Partnership (a “NEGT Interest Sale”) will be completed. Any NEGT Interest Sale may affect JMCS I Management’s administrative services contract with the Partnership. Further, if a NEGT Interest Sale were to be completed, the ability of JMC Selkirk or JMCS I Management to manage the Partnership may be adversely affected, in which event RCM Selkirk GP may be entitled to exercise the Special Management Rights set forth in the Partnership Agreement.

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Results of Operations

     The following table sets forth operating revenue and related data for the years ended December 31, 2003, 2002 and 2001 (dollars and volumes in millions).

     The “capacity factor” of Unit 1 and Unit 2 is the amount of energy produced by each Unit in a given time period expressed as a percentage of the total contract capability amount of potential energy production in that time period.

     The “dispatch factor” of Unit 1 and Unit 2 is the number of hours scheduled for electric delivery (regardless of output level) in a given time period expressed as a percentage of the total number of hours in that time period.

Year Ended December 31, 2003 Compared to the Year Ended December 31, 2002

Overall Results

     Net income was $53.0 million in 2003, an increase of $15.0 million from 2002. This increase was primarily due to higher electric revenues and lower maintenance expenses.

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The following highlights the principal changes in operating revenues and operating expenses.

Operating Revenues

     Operating revenues were $262.8 million for 2003, an increase of $35.2 million from 2002. This increase was primarily due to higher electric revenues, partially offset by lower fuel revenues. Unit 1 electric revenues increased by $15.8 million in 2003 primarily due to escalation in the contract volume component of the Niagara Mohawk monthly contract payment, higher fuel index pricing in the energy component of the Niagara Mohawk monthly contract payment, and higher market electric energy prices. Unit 2 electric revenues increased by $24.5 million in 2003 primarily due to escalation in the Con Edison contract capacity payment, higher fuel index pricing in the Con Edison contract price for delivered energy, and higher volumes of delivered energy. The higher volumes of delivered energy in 2003 primarily resulted from the higher availability of Unit 2. During 2003, five weeks of scheduled maintenance outages were performed on Unit 2, as compared to the performance of ten weeks of scheduled maintenance outages on Unit 2 during 2002. Fuel revenues decreased by $4.9 million in 2003 primarily due to lower volumes of gas transportation optimizations, partially offset by higher natural gas resale prices.

Cost of Revenues

     The cost of revenues was $174.4 million in 2003, an increase of $21.0 million from 2002. This increase was primarily due to higher fuel costs, partially offset by lower maintenance costs. Fuel and transmission costs increased by $29.2 million in 2003 primarily due to the higher price for natural gas under the firm gas supply contracts, partially offset by lower volumes of gas transportation optimizations. Other operating and maintenance costs decreased by $7.7 million in 2003 primarily due to differences in the scope of scheduled maintenance. During 2003, two non-major maintenance outages were performed on Unit 2, as compared to the performance of one non-major maintenance outage on Unit 1 and two major maintenance outages on Unit 2 during 2002.

Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001

Overall Results

     Net income was $38.0 million in 2002, a decrease of $0.4 million from 2001.

The following highlights the principal changes in operating revenues and operating expenses.

Operating Revenues

     Operating revenues were $227.6 million in 2002, a decrease of $2.1 million from 2001. This decrease was primarily due to lower Unit 2 electric revenues, partially offset by higher fuel revenues. Unit 2 electric revenues decreased by $6.1 million in 2002 primarily due to lower fuel index pricing in the Con Edison contract price for delivered energy and

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lower volumes of delivered energy resulting from scheduled major maintenance outages, which occurred in the first (four weeks) and second (six weeks) quarters of 2002. Fuel revenues increased by $2.7 million in 2002 primarily due to higher volumes of gas transportation optimizations, partially offset by lower natural gas resale prices.

Cost of Revenues

     The cost of revenues was $153.4 million in 2002, a decrease of $1.3 million from 2001. This decrease was primarily due to lower fuel and transmission costs; partially offset by higher other operating and maintenance costs. Fuel and transmission costs decreased by $8.8 million in 2002 primarily due to the lower price for natural gas under the firm gas supply contracts, partially offset by higher volumes of gas transportation optimizations. Other operating and maintenance costs increased by $6.1 million in 2002 primarily due to the scheduled major maintenance outages on Unit 2.

Liquidity and Capital Resources

Sources of Cash

     Net cash provided by operating activities in 2003 was $64.4 million as compared to $52.4 million in 2002. The $12.0 million increase was primarily due to higher net income.

     The Partnership believes, based on current conditions and circumstances, it will have sufficient cash flows from operations to fund existing debt obligations and operating costs during 2004.

Credit Agreement

     The Partnership has available for its use a credit agreement, as amended (the “Credit Agreement”), with a maximum available credit (including both outstanding letters of credit and working capital loans) of $10.0 million through August 8, 2005. Outstanding balances of working capital loans under the Credit Agreement bear interest at a base rate with principal and interest payable monthly in arrears. The base rate under the Credit Agreement is the greater of (i) a rate equal to the sum of the federal funds rate plus 0.50%, and (ii) the prime rate publicly announced by Citizens Bank of Massachusetts. The Credit Agreement is available to the Partnership for the purposes of meeting letter of credit requirements under various fuel–related contracts and for meeting working capital requirements. As of December 31, 2003, a letter of credit in the amount of approximately $2.9 million has been issued and there were no amounts drawn under such letter of credit and no balances outstanding under the working capital arrangement.

Uses of Cash

     Net cash used in investing activities in 2003 was $3.4 million as compared to $9.1 million in 2002. Pursuant to the Partnership’s Deposit and Disbursement Agreement, administered by Bankers Trust Company, as depositary agent, the Partnership is required to

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maintain certain Restricted Funds. Net cash flows used in investing activities in 2003 primarily represent deposits of monies into the Debt Service Reserve Funds and net additions to plant and equipment. Net cash flows used in investing activities in 2002 primarily represent deposits of monies into the Major Maintenance Fund and Debt Service Reserve Funds, and net additions to plant and equipment.

     Net cash used in financing activities in 2003 was $60.5 million as compared to $45.1 million in 2002. Net cash flows used in financing activities primarily represent cash distributions to Partners and semi-annual payments of principal on long-term debt.

     The debt service coverage ratio for 2003 calculated pursuant to the Indenture was 1.98:1.

Credit Ratings

     As previously reported in the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, on June 4, 2003 Moody’s Investors Service (“Moody’s”) issued a press release announcing that it had confirmed the senior secured debt of Selkirk Cogen Funding Corporation at Baa3 with a stable rating outlook. Moody’s noted that its action concluded its review for possible downgrade that was initiated on October 8, 2002.

     As previously reported in the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, on July 8, 2003 Standard and Poor’s (“S&P”) issued a press release announcing that it had lowered its corporate credit ratings on two of NEGT’s subsidiaries. S&P stated these ratings actions followed the NEGT Bankruptcy. S&P further stated that the ratings action on the two NEGT subsidiaries did not affect the rating on the senior secured debt of Selkirk Cogen Funding Corporation, which remains at BBB- with a stable outlook.

     A downgrade of the credit ratings of the Partnership’s debt due in 2007 or 2012 by S&P or Moody’s (or both) would not be an event of default under any of the Partnership’s debt agreements and material project contracts or otherwise result in an adverse change to any material term of such agreements and contracts.

Funds

     In connection with the sale of the Bonds, the Partnership entered into the Deposit and Disbursement Agreement (the “D&D Agreement”), which requires the establishment and maintenance of certain segregated funds (the “Funds”) and is administered by Bankers Trust Company, as trustee (the “Trustee”). Pursuant to the D&D Agreement, a number of Funds were established. Some of the Funds have been terminated since the purposes of such Funds were achieved and are no longer required, some Funds are currently active and some Funds activate at future dates upon the occurrence of certain events. The significant Funds that are currently active are the Project Revenue Fund, Major Maintenance Reserve Fund, Interest Fund, Principal Fund, Debt Service Reserve Fund and the Partnership Distribution Fund.

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     All Partnership cash receipts and operating cost disbursements flow through the Project Revenue Fund. As determined on the 20th of each month, any monies remaining in the Project Revenue Fund after the payment of operating costs are used to fund the above named Funds based upon the fund hierarchy and in the amounts (each, a “Fund Requirement”) established pursuant to the D&D Agreement. At December 31, 2003, the balance in this Fund was $4.7 million compared to $3.4 million at December 31, 2002.

     The Major Maintenance Reserve Fund relates to certain anticipated annual and periodic major maintenance to be performed on certain of the Facility’s machinery and equipment at future dates. The Fund Requirement for the Major Maintenance Reserve Fund is developed by the Partnership and approved by an independent engineer for the Trustee and can be adjusted on an annual basis, if needed. At December 31, 2003, the balance in this Fund was $8.6 million compared to $9.4 million at December 31, 2002. During the year ending December 31, 2004, no additional deposits are required to be made into the Major Maintenance Reserve Fund and withdrawals of $5.4 million are expected to be made out of the Major Maintenance Reserve Fund for payment of 2004 major maintenance expenditures.

     The Interest and Principal Funds relate primarily to the current debt service on the outstanding Bonds. The applicable Fund Requirements for the Interest and Principal Funds are the amounts due and payable on the next semi-annual payment date. On December 26, 2003 and 2002, the monies available in the Interest and Principal Funds were used to make the semi-annual interest and principal payments. Therefore, there were no balances remaining in the Interest and Principal Funds at December 31, 2003 and 2002. In order to make debt service payments on June 26, 2004, the June 26, 2004 Interest Fund Requirement is $14.7 million and the Principal Fund Requirement is $9.6 million. In order to make debt service payments on December 26, 2004, the December 26, 2004 Interest Fund Requirement is $14.3 million and the Principal Fund Requirement is $10.0 million.

     The Fund Requirement for the Debt Service Reserve Fund is an amount equal to the maximum amount of debt service due in respect of the Bonds outstanding for any six-month period during the succeeding three-year period. At December 31, 2003 and 2002, the balance in the Debt Service Reserve Fund was $28.3 million and $26.2 million, respectively. The June 26, 2004 Debt Service Reserve Fund Requirement is $30.7 million and the December 26, 2004 Debt Service Reserve Fund Requirement remains at $30.7 million.

     The Gas Contract Extension Fund will be required if the Partnership has not satisfied certain conditions set forth in the Indenture with the respect to the extension or replacement of the Partnership’s firm gas supply agreements by December 26, 2004. If the Gas Contract Extension Fund is required, after December 26, 2004, cash otherwise available for deposit into the Partnership Distribution Fund and subsequent distribution to the Partners under the D&D Agreement will be deposited into the Gas Contract Extension Fund until the balance of the Gas Contract Extension Fund is sufficient to fund all of the scheduled principal payments on the Bonds from June 26, 2010 through June 26, 2012.

     The Partnership Distribution Fund has the lowest priority in the Fund hierarchy and cash distributions to the Partners from this Fund can only be made upon the achievement of

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specific criteria established pursuant to the financing documents, including the D&D Agreement. The Partnership Distribution Fund does not have a Fund Requirement.

Contractual Payment Obligations

     The Partnership has entered into various agreements that result in contractual payment obligations in future years. These contracts include financing arrangements for the Bonds, leases, and contracts for the purchase of goods and services. The following table summarizes cash payments that the Partnership is committed to make under the existing terms of contracts to which the Partnership is a party as of December 31, 2003. This table does not include contingencies. For purchase obligations, amounts shown are largely estimated based upon contract terms, including the fixed, minimum or expected quantities to be purchased at fixed or estimated market-based prices. Actual cash payments will be based upon actual quantities purchased and prices paid and will likely differ, perhaps materially from amounts presented below.

(1)

Reflects amounts outstanding with respect to the Bonds but does not include any amounts outstanding under the Credit Agreement.

(2)

Reflects payment obligations under an operating site lease agreement with General Electric.

(3)

Reflects payment obligations under the Partnership’s firm gas supply, firm gas transportation and firm electric transmission agreements. Such charges may change periodically as a result of changes in regulated tariff rates.

(4)

Reflects payment obligations under the O&M Agreement and a take-or-pay water supply agreement with the Town of Bethlehem.

Market Risk

     Market risk is the risk that changes in market conditions will adversely affect earnings or cashflow. The Partnership categorizes its market risks as interest rate risk, foreign currency risk, energy commodity price risk and credit risk. Immediately below are detailed descriptions of the market risks and explanations as to how each of these risks are managed.

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Interest Rate Risk

     Interest rate risk is the risk that changes in interest rates could adversely affect earnings or cashflows. The Partnership’s cash and restricted cash are sensitive to changes in interest rates. Interest rate changes would result in a change in interest income due to the difference between the current interest rates on cash and restricted cash and the variable rate that these financial instruments may adjust to in the future. Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cashflows as a result of assumed changes in market interest rates. A 10% decrease in 2003 interest rates would be immaterial to the Partnership’s consolidated financial statements.

     The Partnership’s Bonds have fixed interest rates. Changes in the current market rates for the Bonds would not result in a change in interest expense due to the fixed coupon rate of the Bonds.

Foreign Currency Risk

     Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies in relation to the U.S. dollar. The Partnership uses a foreign currency exchange contract to partially hedge foreign currency exposure under a fuel transportation agreement that is denominated in Canadian dollars. In the event the counterparty fails to meet the terms of the foreign currency exchange contract, the Partnership would be exposed to the risk that fluctuating currency exchange rates may adversely impact its financial results. The Partnership’s foreign currency exchange contract terminates on December 25, 2004.

     The Partnership uses sensitivity analysis to measure its foreign currency exchange rate exposure not covered by the foreign currency exchange contract. Based upon a sensitivity analysis at December 31, 2003, a 10 % devaluation of the U.S. Dollar in relation to the Canadian dollar would be immaterial to the Partnership’s consolidated financial statements.

Energy Commodity Price Risk

     The Partnership seeks to reduce its exposure to market risk associated with energy commodities such as electric power and natural gas through the use of long-term sale and purchase contracts.

Credit Risk

     Credit risk is the risk of loss the Partnership would incur if counterparties fail to perform their contractual obligations (these obligations are reflected as Accounts receivable and Due from affiliates on the consolidated balance sheets). The Partnership primarily conducts business with customers in the energy industry, such as investor-owned utilities, energy trading companies, financial institutions, gas production companies and gas transportation companies located in the United States and Canada. This concentration of counterparties may impact the Partnership’s overall exposure to credit risk in that its

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counterparties may be similarly affected by changes in economic, regulatory or other conditions. The Partnership mitigates potential credit losses in accordance with established credit approval practices and limits by dealing primarily with counterparties it considers to be of investment grade.

     As of December 31, 2003, the Partnership’s credit risk is primarily concentrated with the following customers: Con Edison, Niagara Mohawk and the NY ISO, all of whom are considered to be of investment grade.

Accounting Matters

Critical Accounting Policies

     The preparation of consolidated financial statements in accordance with accounting principles generally accepted in the United States involves the use of estimates and assumptions that affect the recorded amount of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Certain of these estimates and assumptions are considered to be Critical Accounting Policies, due to their complexity, subjectivity, and uncertainty, along with their relevance to the financial performance of the Partnership. Actual results may differ substantially from these estimates. These policies and their key characteristics are outlined below.

     The Partnership follows Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (“SFAS No. 133”). SFAS No. 133 requires the Partnership to recognize all derivatives, as defined in the statement, on the consolidated balance sheets at fair value. Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will offset the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recognized in other comprehensive income (loss) until the hedged items are recognized in earnings. Derivatives are classified as asset for derivative contracts and liability for derivative contracts on the consolidated balance sheets (see Note 2 to the Consolidated Financial Statements - Accounting for Derivative Contracts).

Accounting Principles Issued But Not Yet Adopted

     In January 2003, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 46, Consolidation of Variable Interest Entities (“FIN 46”). FIN 46, as subsequently revised in December 2003 (“FIN 46R”), is an interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements (“ARB 51”), and supersedes EITF Issues No. 90-15 and 96-21, which prescribe accounting for lease arrangements with nonsubstantive lessors. This interpretation clarifies the application of ARB 51 to certain entities, defined as “variable interest entities” (“VIEs”), in which equity investors do not have a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. FIN 46R requires that a VIE is to be consolidated by a company, if that company is subject to a majority of the risk of loss

27

from the VIE’s activities or is entitled to receive a majority of the VIE’s residual returns, or both.

     The consolidation requirements of FIN 46 apply immediately to variable interest entities created after January 31, 2003. There were no new variable interest entities created by the Partnership between February 1, 2003 and December 31, 2003. The Partnership is non-public entity as defined by the interpretation. As a non-public entity, the consolidation requirements related to entities or arrangements existing before February 1, 2003 are effective January 1, 2005. The Partnership has not identified any arrangements with potential. The Partnership will continue to evaluate its arrangements for potential FIN 46R application effective January 1, 2005. The Partnership does not expect that implementation of this interpretation will have a significant impact on its consolidated financial statements.

     In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with the Characteristics of Both Liabilities and Equity (“SFAS No. 150”). SFAS No. 150 addresses concerns of how to measure and classify in the statement of financial position certain financial instruments that have characteristics of both liabilities and equity. Freestanding financial instruments including mandatory redeemable financial instruments, obligations to repurchase an issuer’s equity shares by transferring assets, and certain obligations to issue a variable number of shares, must be valued and classified as liabilities. Instruments that are redeemable only upon liquidation or termination of the reporting entity continue to be treated as equity instruments.

     Freestanding financial instruments falling within scope of SFAS No. 150 are initially valued at fair value. Subsequent valuation depends on the nature of the instrument. If both the redemption date and price are fixed, the instrument’s value should be accreted to the redemption amount using the effective interest method. If either the redemption date or amount is not fixed, then the instrument should be carried at the amount of cash that would be paid under the conditions as specified in the contract if the shares were redeemed at the reporting date. Adjustments to the July 1 carrying value of instruments, which were issued prior to the issuance date of the SFAS No. 150, are recorded as a cumulative effect of a change in accounting principle. SFAS No. 150 is effective for non-public entities, as defined in the statement, in the fiscal period beginning after December 31, 2003. The Partnership does not expect the adoption of this Standard to have a significant impact on it consolidated financial statements.

Legal Matters

     The Partnership is a party in various legal proceedings and potential claims arising in the ordinary course of its business. Management does not believe that the resolution of these matters will have a material adverse effect on the Partnership’s consolidated financial position or results of operations. See Part I, Item 3 of this Report for further discussion of significant pending litigation.

28

Regulations and Environmental Matters

     On November 6, 2001, the Partnership received from the DEC the Facility’s Title V operating permit endorsed by the DEC on November 2, 2001 (the “Title V Permit”). The Title V Permit as received by the Partnership contains conditions that conflict with the Partnership’s existing air permits, and the Facility’s compliance with these conditions under certain operating circumstances would be problematic. Further, the Partnership believes that certain of the conditions contained in the Title V Permit are inconsistent with the laws and regulations underlying the Title V program and Title V operating permits issued by the DEC to comparable electric generating facilities in New York. By letter dated November 12, 2001, the Partnership has filed with the DEC a request for an adjudicatory hearing to address and resolve the issues presented by the Title V Permit, and the terms and conditions of the Title V Permit will be stayed pending a final DEC decision on the appeal. At this time it is too early for the Partnership to assess the likely outcome of the adjudicatory hearing and the impact on the Facility.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     The Partnership is exposed to market risk from changes in interest rates, foreign currency exchange rates, energy commodity prices and credit risk, which could affect its future results of operations and financial condition. The Partnership manages its exposure to these risks through its regular operating and financing activities. (See “Market Risk”, included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations above.)

29

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     The financial statements and supplementary data required by this item are presented under Item 15 and are incorporated herein by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

     None.

ITEM 9A. CONTROLS AND PROCEDURES

     An evaluation of the disclosure controls and procedures of the Partnership and Funding Corporation as of December 31, 2003 has been conducted under the supervision and with the participation of the principal executive officer and principal financial officer of both JMC Selkirk, Inc. (as Managing General Partner of the Partnership) and the Funding Corporation. Based on that evaluation, such officers have concluded that, as of such date, the disclosure controls and procedures of the Partnership and Funding Corporation are effective, in that they provide reasonable assurance that such officers are alerted on a timely basis to material information that is required to be included in the Partnership’s and Funding Corporation’s periodic filings under the Securities and Exchange Act of 1934, as amended.

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE FUNDING CORPORATION AND THE MANAGING GENERAL PARTNER

Partnership Governance

     The Managing General Partner is delegated authority under the Partnership Agreement for the management and control of the business and affairs of the Partnership, subject to significant limitations set forth in the Partnership Agreement, including the requirement that the consent of both General Partners (acting through the Management Committee) be obtained for specified actions of the Partnership. Day-to-day management and administration of the Facility is carried out by the Project Management Firm pursuant an administrative services agreement under the supervision of the Managing General Partner.

     The Managing General Partner has a Board of Directors consisting of three persons elected by its sole stockholder, JMC Selkirk Holdings, Inc. (“Holdings”), a direct subsidiary of Beale. Pursuant to a board representation agreement with Teton ECG, Holdings may elect at least four members, and Teton ECG has the right, at its option, to designate a fifth member of the Board of Directors of the Managing General Partner.

Directors and Executive Officers

     The following tables set forth the names, ages and positions of the directors and executive officers of the Funding Corporation and the Managing General Partner and their positions with the Funding Corporation and the Managing General Partner. Directors are elected annually and each elected director holds office until a successor is elected. The executive officers of each of the Funding Corporation and the Managing General Partner are chosen from time to time by vote of its Board of Directors.

     Selkirk Cogen Funding Corporation:

     Managing General Partner:

31

     P. Chrisman Iribe is President and Chief Operating Officer of Power Services Company (formerly PG&E National Energy Group Company), an affiliate of the Partnership, and has been with Power Services Company since it was formed in 1989. Prior to joining Power Services Company, Mr. Iribe was senior vice president for planning, state relations and public affairs with ANR Pipeline Company, a natural gas pipeline company and a subsidiary of the Coastal Corporation. Mr. Iribe has been President of both the Funding Corporation and the Managing General Partner since 1998. Mr. Iribe has been a Director of the Funding Corporation since 1996 and a Director of the Managing General Partner since 1995.

     Thomas E. Legro is Vice President and Controller of Power Services Company, an affiliate of the Partnership, and has been with Power Services Company since July 2001. From January 1994 to June 2001, Mr. Legro was Vice President and Controller of Edison Mission Energy. Mr. Legro was elected Vice President and Controller of both the Funding Corporation and the Managing General Partner on April 1, 2002. Mr. Legro was elected Chief Accounting Officer and Director of both the Funding Corporation and the Managing General Partner on February 1, 2003.

     Sanford L. Hartman is Vice President, Chief Counsel and Secretary of Power Services Company, an affiliate of the Partnership, and has been with Power Services Company since 1990. Prior to joining Power Services Company, Mr. Hartman was counsel to Long Lake Energy Corporation, an independent power producer with headquarters in New York City, and was an attorney with the Washington, D.C. law firm of Bishop, Cook, Purcell & Reynolds. Mr. Hartman has been a Director of both the Funding Corporation and the Managing General Partner since 1999. Mr. Hartman was elected Assistant Secretary of both the Funding Corporation and the Managing General Partner on July 15, 2003.

General Partners’ Representatives of the Management Committee

     The Management Committee established under the Partnership Agreement consists of one representative of each of the General Partners. Each General Partner has a voting representative on the Management Committee, which, subject to certain limited exceptions, acts by unanimity. Teton Selkirk is entitled to name a designee to participate on a non-voting basis in meetings of the Management Committee.

Audit Committee

     The Board of Directors of each of the Managing General Partner and the Funding Corporation performs the functions and responsibilities of an audit committee of the Partnership and Funding Corporation, respectively. Each such Board of Directors has determined that one of its members, Thomas E. Legro, is an audit committee financial expert as defined in Item 401(h) of the Securities and Exchange Commission’s Regulation S-K, and has also determined that Mr. Legro is not “independent” within the meaning of such provision because he is an executive officer of both the Partnership and Funding Corporation, as well as an employee of an affiliated person, the Project Management Firm. The Partnership and Funding Corporation, however, are not required under the Commission’s rules implementing Section 10A(m) of the Securities Exchange Act of 1934, as amended, to have an audit

32

committee consisting of “independent” members because they are not listed issuers within the meaning of such rules.

Code of Ethics

     As employees of the Project Management Firm, the principal executive officer, principal financial officer and chief accounting officer or controller of both the Managing General Partner and Funding Corporation are subject to a code of business conduct and ethics contained within the NEGT employee handbook most recently modified in December 2003 (the “Code of Ethics”). The Code of Ethics is intended to promote honest and ethical conduct and compliance with the laws and governmental rules and regulations to which the companies are subject. A printed copy of the Code of Ethics will be provided free of charge to any bondholder upon written request to JMC Selkirk, Inc., c/o NEGT, Attn: Vice President of Finance, at the Partnership’s principal executive offices listed on the cover page of this Report.

ITEM 11. EXECUTIVE AND BOARD COMPENSATION AND BENEFITS

     No cash compensation or non-cash compensation was paid in any prior year or during the year ended December 31, 2003 to any of the officers, directors and representatives referred to under Item 10 above for their services to the Funding Corporation, the Managing General Partner or the Partnership. Overall management and administrative services for the Partnership are being performed by the Project Management Firm at agreed-upon billing rates, which are adjusted quadrennially, if necessary, pursuant to the Administrative Services Agreement.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The Partnership is a limited partnership wholly owned by its Partners. The following information is given with respect to the Partners of the Partnership:

* Formerly Aquila Selkirk, Inc.

	(1)		None of the persons listed has the right to acquire beneficial ownership of securities as specified in Rule 13d-3(d) under the Exchange Act. Each of the persons listed has sole voting power and sole investment power with respect to the beneficial ownership interests described, subject to certain partnership interest pledge agreements made in favor of the Funding Corporation’s and the Partnership’s lenders.
	(2)		Percentages indicate the interest of (i) each of the Partners in certain priority distributions of available cash of the Partnership, up to fixed semi-annual amounts (the “Level I Distributions”), (ii) JMC Selkirk, Investors and Teton Selkirk in 99% of distributions of the remaining available cash of the Partnership; and (iii) each of the Partners in the residual tier of interests in cash distributions after the initial 18-year period following the completion of Unit 2 (or, if later, the date when all Level I Distributions have been paid).
	(3)		Beale is the indirect beneficial owner of JMC Selkirk and a 50% indirect beneficial owner of Investors. The capital stock of Beale is held by National Energy Power Company, LLC (89.1%) and Cogentrix (10.9%). NEGT is the indirect beneficial owner of National Energy Power Company, LLC. Cogentrix is beneficially owned by

34

Cogentrix Energy, Inc., an indirect wholly owned subsidiary of Goldman Sachs Group, Inc.

	(4)		ArcLight Energy Partners Fund I, L.P., a private equity fund focused on the electric power sector, is a 50% indirect beneficial owner of Investors.
	(5)		Robert C. McNair (88.3%) and members of his family (11.7%) are the beneficial owners of RCM Selkirk GP. Robert C. McNair is the beneficial owner of RCM Selkirk LP. Mr. McNair has voting control of each of RCM Selkirk GP and RCM Selkirk LP.
	(6)		ArcLight Energy Partners Fund I, L.P. and ArcLight Energy Partners Fund II, L.P., both private equity funds focused on the electric power sector, are the indirect beneficial owners of Teton Selkirk.

     Except as specifically provided or required by law and in certain other limited circumstances provided in the Partnership Agreement, Limited Partners may not participate in the management or control of the Partnership. The Managing General Partner is an affiliate of Investors, which is a Limited Partner, and JMCS I Management, the Project Management Firm. RCM Selkirk GP and RCM Selkirk LP are also affiliated.

     All of the issued and outstanding capital stock of the Funding Corporation is owned by the Partnership.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     JMCS I Management, an indirect, wholly owned subsidiary of NEGT, provides management and administrative services for the Partnership under the Administrative Services Agreement. All of the directors of the Managing General Partner and the Funding Corporation listed in Item 10 of this Report are also directors or officers, as the case may be, of JMCS I Management. See Note 9 to the Consolidated Financial Statements for a discussion of the Partnership’s related party transactions.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

     The following table presents fees for professional services rendered by Deloitte & Touche LLP and billed to the Partnership for the audit of the annual consolidated financial statements of the Partnership and its subsidiary (Funding Corporation) for the years ended December 31, 2003 and 2002, and fees for other services billed by Deloitte & Touche LLP during those periods:

Audit Fees – Audit fees relate to services rendered in connection with the audit of the annual financial statements included in the Partnership’s Annual Reports on Form 10-K and the quarterly reviews of financial statements included in the Partnership’s Quarterly Forms 10-Q.

Audit-Related Fees – Audit-related fees relate to services for consultations concerning financial accounting and reporting matters. There were no Audit-Related Fees in 2003 or 2002.

Tax Fees – Tax fees relate to services for tax compliance.

All Other Fees – There were no fees for other services of Deloitte & Touche LLP in 2003 or 2002.

Pre-Approval Policies

     The Board of Directors of JMC Selkirk acts as the audit committee for the Partnership (“Audit Committee”).

     The Audit Committee approves all audit and non-audit services provided by the Partnership’s independent auditor prior to the engagement of the independent auditor with respect to such services. The Chief Accounting Officer, who is also a member of the Audit Committee, has the authority to approve any additional audit services and permissible non-audit services provided the Audit Committee is informed of such approval at its next regularly scheduled meeting.

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     All of the services provided by Deloitte & Touche LLP for fiscal year 2003, and related fees, were approved in advance by the Audit Committee in accordance with established approval policies.

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PART IV

ITEM 15. FINANCIAL STATEMENTS, EXHIBITS AND REPORTS ON FORM 8-K

(a)

1.   Financial Statements

The following financial statements are filed as part of this Report:

	2.		Exhibits
			The exhibits listed on the accompanying Index to Exhibits are filed as part of this Report.

(b)

Reports on Form 8-K

On June 6, 2003, the Registrants filed a report on Form 8-K disclosing the ratings action by Moody’s Investors Service.

On July 22, 2003, the Registrants filed a report on Form 8-K disclosing the PG&E National Energy Group, Inc. Bankruptcy.

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INDEPENDENT AUDITORS’ REPORT

To the Partners of
      Selkirk Cogen Partners, L.P.:

     We have audited the accompanying consolidated balance sheets of Selkirk Cogen Partners, L.P. (a Delaware limited partnership) and its subsidiary (collectively, the “Partnership”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, changes in partners’ deficits, and cash flows for each of the three years in the period ended December 31, 2003. These consolidated financial statements are the responsibility of the Partnership’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. 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 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, such consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

     See Note 1 to the consolidated financial statements for discussion of the financial difficulties of National Energy & Gas Transmission, Inc. (formerly PG&E National Energy Group, Inc.) and certain affiliates.

     As discussed in Note 2 to the consolidated financial statements, during 2003, the Partnership adopted new accounting standards to account for asset retirement obligations. Also, during 2001, the Partnership adopted new accounting standards relating to derivatives and certain interpretations issued by the Derivatives Implementation Group of the Financial Accounting Standards Board.

/s/ DELOITTE & TOUCHE LLP

F-1

SELKIRK COGEN PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2003 AND 2002
(In Thousands)

The accompanying Notes to the Consolidated Financial Statements are an integral part of these financial statements.

F-2

SELKIRK COGEN PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(In Thousands)

The accompanying Notes to the Consolidated Financial Statements are an integral part of these financial statements.

F-3

SELKIRK COGEN PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ DEFICITS
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(In Thousands)

The accompanying Notes to the Consolidated Financial Statements are an integral part of these financial statements.

F-4

SELKIRK COGEN PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(In Thousands)

The accompanying Notes to the Consolidated Financial Statements are an integral part of these financial statements.

F-5

SELKIRK COGEN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001

1.

ORGANIZATION AND OPERATION

     Selkirk Cogen Partners, L.P. was organized on December 15, 1989 as a Delaware limited partnership. Selkirk Cogen Funding Corporation (the “Funding Corporation”), a wholly owned subsidiary of Selkirk Cogen Partners, L.P. (collectively, “the Partnership”), was organized for the sole purpose of facilitating financing activities of the Partnership and has no other operating activities (Note 5). The obligations of the Funding Corporation with respect to the bonds are unconditionally guaranteed by the Partnership.

     The managing general partner of the Partnership is JMC Selkirk, Inc. (“JMC Selkirk” or the “Managing General Partner”). The other general partner of the Partnership (together with JMC Selkirk, the “General Partners”) is RCM Selkirk GP, Inc. (“RCM Selkirk GP”). The limited partners of the Partnership (the “Limited Partners,” and together with the General Partners, the “Partners”) are JMC Selkirk, PentaGen Investors, L.P. (“Investors”), Teton Selkirk, LLC (“Teton Selkirk”, formerly Aquila Selkirk, Inc.) and RCM Selkirk, L.P. (“RCM Selkirk LP”).

     The Managing General Partner is responsible for managing and controlling the business and affairs of the Partnership, subject to certain powers, which are vested in the management committee of the Partnership (the “Management Committee”) under the Partnership Agreement. Each General Partner has a voting representative on the Management Committee, which, subject to certain limited exceptions, acts by unanimity. Thus, the General Partners, and principally the Managing General Partner, exercise control over the Partnership. JMCS I Management, Inc. (“JMCS I Management”), an affiliate of the Managing General Partner, is acting as the project management firm (the “Project Management Firm”) for the Partnership, and as such is responsible for the implementation and administration of the Partnership’s business under the direction of the Managing General Partner. Upon the occurrence of certain events specified in the Partnership Agreement, RCM Selkirk GP may assume the powers and responsibilities of the Managing General Partner and of the Project Management Firm. Under the Partnership Agreement, each General Partner other than the Managing General Partner may convert its general partnership interest to that of a Limited Partner.

     JMC Selkirk is an indirect, wholly owned subsidiary of Beale Generating Company (“Beale”), which is jointly owned by Cogentrix Eastern America, Inc. (10.9% interest) and National Energy Power Company, LLC (formerly PG&E Generating Power Group, LLC) (89.1% interest). Cogentrix Eastern America, Inc. is a subsidiary of Cogentrix Energy, Inc., an indirect, wholly owned subsidiary of Goldman Sachs Group, Inc. National Energy Power Company, LLC is a direct, wholly owned subsidiary of NEGT Energy Company, LLC (formerly, PG&E Generating Company, LLC), an indirect, wholly owned subsidiary of

F-6

National Energy & Gas Transmission, Inc (“NEGT”, formerly, PG&E National Energy Group, Inc.). NEGT is an indirect subsidiary of PG&E Corporation.

     The Partnership was formed for the purpose of constructing, owning and operating a natural gas-fired, combined-cycle cogeneration facility located on General Electric Company’s (“General Electric”) property in Bethlehem, New York (the “Facility”). The Partnership has long-term contracts for the sale of electric capacity and energy produced by the Facility with Niagara Mohawk Power Corporation (“Niagara Mohawk”) and Consolidated Edison Company of New York, Inc. (“Con Edison”) and steam produced by the Facility with GE Plastics, a core business of General Electric Company (“General Electric”). The Facility consists of one unit (“Unit 1”) with an electric generating capacity of approximately 79.9 megawatts (“MW”) and a second unit (“Unit 2”) with an electric generating capacity of approximately 265 MW. Unit 1 commenced commercial operations on April 17, 1992, and Unit 2 commenced commercial operations on September 1, 1994. Both units are fueled by natural gas purchased principally from Canadian suppliers (Note 8). Unit 1 and Unit 2 have been designed to operate independently for electrical generation, while thermally integrated for steam generation, thereby optimizing efficiencies in the combined performance of the Facility.

     The Facility is certified by the Federal Energy Regulatory Commission as a qualifying facility (“Qualifying Facility”) under the Public Utility Regulatory Policy Act of 1978, as amended (“PURPA”). As a Qualifying Facility, the prices charged for the sale of electricity and steam are not regulated. Certain fuel supply and transportation agreements entered into by the Partnership are also subject to regulation on the federal and provincial levels in Canada. The Partnership has obtained all material Canadian governmental permits and authorizations required for its operation.

     Relationship with NEGT — NEGT owns an indirect interest in the Partnership, and through its indirect subsidiaries, JMC Selkirk and JMCS I Management, manages the Partnership. On July 8, 2003, NEGT and certain subsidiaries voluntarily filed petitions for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (collectively, the “NEGT Bankruptcy”) in the Greenbelt Division of the United States Bankruptcy Court for the District of Maryland (the “Bankruptcy Court”). The subsidiaries that filed voluntarily petitions and were disclosed in previous reports as related parties of the Partnership with which it engaged in transactions are: NEGT Energy Trading-Power, L.P. (“NEGT Energy Trading-Power”, formerly PG&E Energy Trading-Power, L.P.) and NEGT Energy Trading—Gas Corporation (“NEGT Energy Trading-Gas”, formerly PG&E Energy Trading-Gas Corporation). There were no amounts due to or from these subsidiaries at December 31, 2003.

     None of the Partnership or its NEGT affiliated partners (JMC Selkirk and Investors) are parties to the NEGT Bankruptcy. The Managing General Partner believes that JMC Selkirk, Investors, and the Partnership will not be substantively consolidated with NEGT in any bankruptcy proceeding involving NEGT, and that the NEGT Bankruptcy will not have a material adverse impact on the Partnership’s operations.

     However, the Partnership cannot be certain that the NEGT Bankruptcy will not affect NEGT’s arrangements with respect to the Partnership or the ability of JMC Selkirk or JMCS I Management to manage the Partnership. The Partnership Agreement provides certain management rights to RCM Selkirk GP in the event that JMC Selkirk were to be included as a debtor within the NEGT Bankruptcy, or either JMC Selkirk or JMCS I Management were to be in material default of its obligations to the Partnership (following notice and a 120 day cure period). These protections (the “Special Management Rights”) include (i) the removal of JMC Selkirk as the managing general partner, (ii) the appointment of itself as the successor managing general partner, and (iii) the termination of the administrative services agreement with JMCS I Management and subsequent appointment of a RCM Selkirk GP affiliate as the project management firm. Enforcement of these rights by RCM Selkirk GP could, however, be delayed or impeded as a result of any bankruptcy proceeding involving JMC Selkirk. Moreover, the bankruptcy of any partner of the Partnership would be an event of default under the Partnership’s Credit Agreement. (Note 5)

F-7

     On February 26, 2004, NEGT filed with the Bankruptcy Court its Third Amended Plan of Reorganization and the related Disclosure Statement (the “POR”). The POR contemplates that, unless NEGT sells its power generation and pipeline businesses as described in the POR, it will retain and continue to operate these businesses, separate from PG&E Corporation, and will issue new debt securities and common stock. NEGT’s indirect ownership interest in the general partner interest of JMC Selkirk and the limited partner interests of JMC Selkirk and Investors in the Partnership are included within its power generation business. The Partnership cannot predict whether a sale by NEGT of its interest in the Partnership (a “NEGT Interest Sale”) will be completed. Any NEGT Interest Sale may affect JMCS I Management’s administrative services contract with the Partnership. Further, if a NEGT Interest Sale were to be completed, the ability of JMC Selkirk or JMCS I Management to manage the Partnership may be adversely affected, in which event RCM Selkirk GP may be entitled to exercise the Special Management Rights set forth in the Partnership Agreement.

2.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation - The accompanying consolidated financial statements include Selkirk Cogen Partners, L.P., and the Funding Corporation. All significant intercompany balances and transactions have been eliminated.

Use of Estimates - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets, liabilities and disclosure of contingencies at the date of the consolidated financial statements. Actual results could differ from these estimates.

Accounting for Derivative Contracts - The Partnership follows Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (“SFAS No. 133”). SFAS No. 133 requires the Partnership to recognize all derivatives, as defined in the statement, on the consolidated balance sheets at fair value. Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will offset the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recognized in other

F-8

comprehensive income (loss) until the hedged items are recognized in earnings. Derivatives are classified as liabilities for derivative contracts on the consolidated balance sheets.

     On April 1, 2002, the Partnership implemented two interpretations issued by the Financial Accounting Standard Board’s (“FASB”) Derivatives Implementation Group (“DIG”). DIG Issues C15 and C16 changed the definition of normal purchases and sales included in SFAS No. 133. Previously, certain derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business were exempt from the requirements of SFAS No. 133 under the normal purchases and sales exemption, and thus were not marked-to-market and reflected on the balance sheet like other derivatives. Instead, these contracts were recorded on an accrual basis.

     DIG Issue C15 changed the definition of normal purchases and sales for certain power contracts. The Partnership determined that all of its power contracts continue to qualify for the normal purchases and sales exemption. DIG Issue C16 disallowed normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. The Partnership determined that one of its long-term fuel contracts failed to continue qualifying for the normal purchase exemption under the requirements of DIG Issue C16. However, because the long-term fuel contract has market based pricing, the Partnership currently estimates its fair value to always be zero, resulting in no impact to the Partnership’s consolidated financial statements.

     DIG Issue C10 disallowed normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. The Partnership determined that certain of its gas contracts no longer qualify for normal purchases and sales treatment under this interpretation. Beginning July 1, 2001, these contracts were required to be recorded on the balance sheet at fair value and marked-to-market through earnings. The cumulative effect of this change in accounting principle was the recording of a loss totaling approximately $519,000 on July 1, 2001. Changes in the fair value of these contracts are recorded on the consolidated statements of operations as an unrealized gain or loss on derivative contracts (Note 3).

     The transition adjustment to implement SFAS No. 133 on January 1, 2001, was a negative adjustment of approximately $8,968,000 to other comprehensive income, a component of partners’ equity and had no effect on net income. The Partnership has two foreign currency exchange contracts to hedge against fluctuations of fuel transportation costs, which are denominated in Canadian dollars. The fair value of these contracts is recorded on the consolidated balance sheets as a liability for derivative contracts (Note 3).

     The fair values of derivative contracts are based on management’s best estimates considering various factors including market quotes, forward price curves, time value, and volatility factors. The values are adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under present market conditions and to reflect creditworthiness of the counterparty.

F-9

Cash Equivalents - For the purposes of the accompanying consolidated statements of cash flows, the Partnership considers all unrestricted, highly liquid investments with original maturities of three months or less to be cash equivalents.

Restricted Funds and Long-Term Restricted Funds - Restricted funds and long-term restricted funds include cash and cash equivalents whose use is restricted under a deposit and disbursement agreement (the “D&D Agreement”) (Note 5). Restricted funds associated with transactions or events occurring beyond one year are classified as long-term. All other restricted funds are classified as current assets.

Inventory - - Inventories are stated at the lower of cost or market and consist mainly of spare parts. Costs for supplies and spare parts are determined on an average cost method.

     During 2003, the Partnership entered into an agreement with an unrelated third party to purchase spare parts with a fair value of approximately $7,390,000 (“New Parts”). In consideration for the purchase of the New Parts, over the next two years, the Partnership will exchange cash and spare parts used in production (“Old Parts”). The value of the New Parts received into inventory will be recorded at the cash amount of approximately $4,817,000, which is equivalent to the fair value of the New Parts less the credit received for the Old Parts. As of December 31, 2003 approximately $3,798,000 of the New Parts have been received into inventory. As this transaction constitutes a like-kind exchange of similar assets and is not the culmination of the earnings process, no gain or loss will be recorded.

Plant and Equipment - Plant and equipment is stated at cost, net of accumulated depreciation. Depreciation is computed on a straight-line basis over the estimated useful lives of the related assets. Capitalized modifications to leased properties are amortized using the straight-line method over the shorter of the lease term, through September 2014, or the asset’s estimated useful life. Other assets are depreciated as follows:

Deferred Financing Charges - Deferred financing charges relate to costs incurred for the issuance of long-term bonds and are amortized using the effective interest method over the term of the related loans.

Real Estate Taxes - Real estate tax payments made under the Partnership’s payment in lieu of taxes (“PILOT”) agreement (Note 8) are recognized on a straight-line basis over the term of the agreement.

Revenue Recognition - Revenues from the sale of electricity and steam are recorded based on monthly output delivered as specified under contractual terms. Revenues from the sale of gas are recorded in the month sold. All revenues are recorded in accordance with the Securities and Exchange Commission Staff Accounting Bulletin (“SAB”) No. 101, Revenue Recognition, as amended.

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Deferred Revenues - The net cash receipts and restructuring costs resulting from the execution of the Amended and Restated Niagara Mohawk Power Purchase Agreement are deferred and are amortized over the term of the Amended and Restated Niagara Mohawk Power Purchase Agreement (Note 8).

Accumulated Other Comprehensive Income (Loss) -Accumulated other comprehensive income (loss) reports a measure for changes in equity of an enterprise that result from transactions and other economic events other than transactions with partners. The Partnership’s accumulated other comprehensive income (loss) consists principally of changes in the market value of certain currency exchange contracts.

Income Taxes - The tax results of Partnership activities flow directly to the partners; as such, the accompanying consolidated financial statements do not reflect provisions for federal or state income taxes.

Adoption of New Accounting Pronouncements - On January 1, 2003, the Partnership adopted SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). SFAS No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets. The statement requires that an asset retirement obligation be recorded at fair value in the period in which it is incurred, if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the long-lived asset.

     Upon implementation of this statement, the Partnership recorded approximately $45,000 to its plant and equipment to reflect the fair value of the asset retirement costs as of the date the obligation was incurred, and recognized approximately $83,000 for asset retirement obligations. The cumulative effect of the change in accounting principle as a result of adopting this statement was a loss of approximately $53,000.

     If this statement had been adopted on January 1, 2001, the pro forma effects on earnings of the accounting change for the years ended December 31, 2002 and 2001 would not have been material.

     In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities (“SFAS No. 146”), which is effective for exit and disposal activities initiated after December 31, 2002. SFAS No. 146 supersedes previous accounting guidance with respect to exit or disposal activities, and requires that a liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. It also established that a liability should be measured and recorded at fair value. This statement was adopted on January 1, 2003 and did not have an impact on the Partnership’s consolidated financial statements.

     In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”). This interpretation expands on the accounting guidance of SFAS No. 5,

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Accounting for Contingencies, SFAS No. 57, Related Party Disclosures and SFAS No. 107, Disclosures about Fair Value of Financials Instruments.

     FIN 45 elaborates on existing disclosure requirements for most guarantees in interim and annual financial statements. It also clarifies that at the time a company issues a guarantee, it must recognize an initial liability for the fair value of the obligation it assumes under that guarantee, including its ongoing obligation to stand ready to perform over the term of the guarantee in the event that specified triggering events or conditions occur. FIN 45’s disclosure requirements are effective for periods ending after December 15, 2002, and the recognition and measurement provisions are to be prospectively applied to guarantees issued or modified after December 31, 2002. This interpretation was adopted on January 1, 2003 and did not have a material impact on the Partnership’s consolidated financial statements.

     In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS No. 149”). SFAS No. 149 amends and clarifies the accounting and reporting for derivative instruments, including certain derivatives embedded in other contracts, and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies under what circumstances a contract with an initial net investment meets the characteristics of a derivative according to SFAS No. 133 and when a derivative contains a financing component that warrants special reporting in the statement of cash flows. The provisions of SFAS No. 149 that relate to SFAS No. 133 implementation issues that have been effective for periods that began prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates. The requirements of this statement are effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. This statement was adopted on July 1, 2003 and did not have an impact on the Partnership’s consolidated financial statements.

     In May 2003, the Emerging Issues Task Force (“EITF”) reached consensus on Issue No. 01-8, Determining Whether an Arrangement Contains a Lease. (“EITF 01-8”). This standard is effective for all new or modified arrangements entered into after June 30, 2003, and establishes criteria to be applied in determining if such an arrangement is in effect a lease. If the new or modified agreement is determined to be a lease then such agreement is subject to lease accounting treatment and disclosure requirements principally found in SFAS No. 13, Accounting for Leases. EITF 01-8 was adopted in July 1, 2003 and did not have an impact on the Partnership’s consolidated financial statements.

Accounting Principles Issued But Not Yet Adopted - In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities (“FIN 46”). FIN 46, as subsequently revised in December 2003 (“FIN 46R”), is an interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements (“ARB 51”), and supersedes EITF Issues No. 90-15 and 96-21, which prescribe accounting for lease arrangements with nonsubstantive lessors. This interpretation clarifies the application of ARB 51 to certain entities, defined as “variable interest entities” (“VIEs”), in which equity investors do not have a controlling financial interest or do not have sufficient equity at risk for the entity to finance it activities without additional subordinated financial support. FIN 46R requires that a VIE is to be consolidated by a company, if that company is subject to a majority of the risk of loss from the VIE’s activities or is entitled to receive a majority of the VIE’s residual returns, or both.

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     The consolidation requirements of FIN 46 apply immediately to variable interest entities created after January 31, 2003. There were no new variable interest entities created by the Partnership between February 1, 2003 and December 31, 2003. The Partnership is non-public entity as defined by the interpretation. As a non-public entity, the consolidation requirements related to entities or arrangements existing before February 1, 2003 are effective January 1, 2005. The Partnership has not identified any arrangements with potential VIEs. The Partnership will continue to evaluate its arrangements for potential FIN 46R application effective January 1, 2005. The Partnership does not expect that implementation of this interpretation will have a significant impact on its consolidated financial statements.

     In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with the Characteristics of Both Liabilities and Equity (“SFAS 150”). SFAS No. 150 addresses concerns of how to measure and classify in the statement of financial position certain financial instruments that have characteristics of both liabilities and equity. Freestanding financial instruments including mandatory redeemable financial instruments, obligations to repurchase an issuer’s equity shares by transferring assets, and certain obligations to issue a variable number of shares, must be valued and classified as liabilities. Instruments that are redeemable only upon liquidation or termination of the reporting entity continue to be treated as equity instruments.

     Freestanding financial instruments falling within scope of SFAS No. 150 are initially valued at fair value. Subsequent valuation depends on the nature of the instrument. If both the redemption date and price are fixed, the instrument’s value should be accreted to the redemption amount using the effective interest method. If either the redemption date or amount is not fixed, then the instrument should be carried at the amount of cash that would be paid under the conditions as specified in the contract if the shares were redeemed at the reporting date. Adjustments to the July 1 carrying value of instruments, which were issued prior to the issuance date of the SFAS No. 150, are recorded as a cumulative effect of a change in accounting principle. SFAS No. 150 is effective for non-public entities, as defined in the statement, in the fiscal period beginning after December 31, 2003. The Partnership does not expect the adoption of this standard to have a significant impact on it consolidated financial statements.

Reclassifications - Certain reclassifications have been made in the 2002 and 2001 consolidated financial statements to conform to the current-year presentation.

3.

ACCOUNTING FOR DERIVATIVE CONTRACTS

Currency exchange contracts — The Partnership has had two foreign currency exchange contracts to hedge against fluctuations in fuel transportation costs, which are denominated in Canadian dollars. Under the Unit 1 currency exchange agreement, which had a term of ten years and expired on December 25, 2002, the Partnership exchanged approximately $368,000 U.S. dollars for $458,000 Canadian dollars on a monthly basis. Under the Unit 2 currency exchange agreement, which commenced on May 25, 1995 and terminates on December 25, 2004, the Partnership exchanges approximately $1,044,000 U.S. dollars for $1,300,000 Canadian dollars on a monthly basis. Effective January 1, 2001, the Partnership began accounting for its foreign exchange contracts as cash flow hedges and recorded on the

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consolidated balance sheets a liability for derivative contracts with the offset in other comprehensive income (loss) (Note 2).

The schedule below summarizes the activities affecting accumulated other comprehensive loss from derivative contracts for the years ended December 31, 2003 and 2002 (in thousands):

     The Partnership expects that net derivative losses of approximately $498,000, included in accumulated other comprehensive loss as of December 31, 2003, will be reclassified into earnings within the next twelve months.

Peak shaving arrangements - The Partnership enters into peak shaving arrangements whereby it grants to local distribution companies or other purchasers a call on a specified portion of the Partnership’s firm natural gas supply for a specified number of days during the winter season. Revenues from peak shaving arrangements for the year ended December 31, 2003 were approximately $2,878,000, as compared to approximately $446,000 in 2002 and approximately $744,000 in 2001. Effective July 1, 2001, the Partnership began accounting for its peak shaving arrangements as derivatives under SFAS No. 133 and recorded a loss of approximately $519,000 reflecting the cumulative effect of a change in accounting principle. Changes in the fair value of peak shaving arrangements are recorded on the consolidated statements of operations as an unrealized gain or loss on derivative contracts. There was no unrealized gain or loss on derivative contracts for the year ended December 31, 2003. The unrealized loss on derivative contracts for the year ended December 31, 2002 was approximately $446,000, as compared to an unrealized gain on derivative contracts of approximately $965,000 in 2001.

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4.

PARTNERS’ CAPITAL

The general and limited partners and their respective equity interests are as follows:

(1)

Formerly Aquila Selkirk, Inc.

(2)

Formerly Aquila East Coast Generation, Inc.

     Under the terms of the amended partnership agreement, 99% of cash available for preferred distribution, as defined, is first allocated to the partners in accordance with their respective preferred equity interest and the remaining 1% is allocated based on the original ownership structure between Beale and Teton East Coast Generation, LLC (“Teton ECG”). Any remaining funds in excess of preferred distribution are allocated 99% to the original equity holders and 1% to the preferred equity holders. At the earlier of the eighteenth anniversary of Unit 2’s commercial operations (August 2012) or the date on which all the preferred partners achieve a specified return as defined in the partnership agreement, distributions will be made in accordance with the following residual interest: Beale at 64.8%, Teton ECG at 17.7%, and Robert C. McNair at 17.5%.

5.

DEBT FINANCING

Long-Term Bonds - On May 9, 1994, the Funding Corporation issued an aggregate of $392,000,000 in bonds. The bonds consist of $165,000,000 bearing interest at 8.65% per annum through December 26, 2007. Principal and interest are payable semi-annually on June 26 and December 26. Principal payments commenced on June 26, 1996. The bonds also include $227,000,000 bearing interest at 8.98% per annum through June 26, 2012. Interest is payable semiannually on June 26 and December 26 and principal payments commence on December 26, 2007, and are payable semi-annually thereafter.

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The scheduled principal payments on the bonds are as follows (in thousands):

     The bonds are secured by substantially all of the assets of the Partnership and are nonrecourse to the individual partners. The trust indenture restricts the ability of the Partnership to make distributions to the partners under certain circumstances.

     In connection with the sale of the bonds, the Partnership entered into the D&D Agreement, which requires the establishment and maintenance of certain segregated funds (the “Funds”) and is administered by Bankers Trust Company as trustee (the “Trustee”). The Funds that are active and included in current restricted funds in the accompanying consolidated balance sheets include the Project Revenue Fund, Current Portion of the Major Maintenance Reserve Fund, Principal Fund, Interest Fund, and the Partnership Distribution Fund. The Funds that are active and included in long-term restricted funds in the accompanying consolidated balance sheets are the Long-Term Portion of the Major Maintenance Reserve Fund and Debt Service Reserve Fund.

     All Partnership cash receipts and operating cost disbursements flow through the Project Revenue Fund. As determined on the 20th of each month, any monies remaining in the Project Revenue Fund after the payment of operating costs are used to fund the above named Funds based upon the fund hierarchy and in amounts (each, a “Fund Requirement”) established pursuant to the D&D Agreement. The balance in the Project Revenue Fund was approximately $4,711,000 at December 31, 2003, compared to approximately $3,415,000 at December 31, 2002.

     The Major Maintenance Reserve Fund relates to certain anticipated annual and periodic major maintenance to be performed on certain of the Facility’s machinery and equipment at future dates. The Fund Requirement for the Major Maintenance Reserve Fund is developed by the Partnership and approved by an independent engineer for the Trustee and can be adjusted on an annual basis, if needed. The balance in the Major Maintenance Reserve Fund was approximately $8,553,000 at December 31, 2003, compared to approximately $9,355,000 at December 31, 2002.

     The Interest and Principal Funds relate primarily to the current debt service on the outstanding Bonds. The applicable Fund Requirements for the Interest and Principal Funds are the amounts due and payable on the next semi-annual payment date. On December 26, 2003 and 2002, the monies available in the Interest and Principal Funds were used to make the semi-annual interest and principal payments. Therefore, there were no balances remaining in the Interest and Principal Funds at December 31, 2003 and 2002.

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     The Fund Requirement for the Debt Service Reserve Fund is an amount equal to the maximum amount of debt service due in respect of the Bonds outstanding for any six-month period during the succeeding three-year period. The balance in the Debt Service Reserve Fund was approximately $28,283,000 at December 31, 2003, compared to approximately $26,229,000 at December 31, 2002.

     The Partnership Distribution Fund has the lowest priority in the fund hierarchy. Cash distributions to the Partners from this fund can only be made upon the achievement of specific criteria established pursuant to the financing documents, including the D&D Agreement. The Partnership Distribution Fund does not have a Fund Requirement.

Credit Agreement - The Partnership has available for its use a credit agreement, as amended (the “Credit Agreement”), with a maximum available credit (including both outstanding letters of credit and working capital loans) of $10,000,000 through August 8, 2005. Outstanding balances of working capital loans under the Credit Agreement bear interest at a base rate with principal and interest payable monthly in arrears. The base rate under the Credit Agreement is the greater of (i) a rate equal to the sum of the federal funds rate plus 0.50%, and (ii) the prime rate publicly announced by Citizens Bank of Massachusetts. The Credit Agreement is available to the Partnership for the purposes of meeting letter of credit requirements under various fuel-related contracts and for meeting working capital requirements. As of December 31, 2003, a letter of credit in the amount of approximately $2,925,000 has been issued and there were no amounts drawn under such letter of credit and no balances outstanding under the working capital arrangement.

6.

FAIR VALUE OF FINANCIAL INSTRUMENTS

     The following methods and assumptions were used by the Partnership in estimating the fair value of its financial instruments:

Cash and Cash Equivalents, Restricted Funds, Due from Affiliates, Due to Affiliates, Accounts Receivable, Accounts Payable, and Accrued Expenses - The carrying amounts reported in the accompanying consolidated balance sheets of these accounts approximate their fair values due primarily to the short-term maturities of these accounts.

Long-Term Bonds - The fair value of the long-term bonds is based on the current market rates for the bonds. The fair value of the long-term bonds (including the current portion) was approximately $372,040,000 at December 31, 2003, compared to approximately $324,964,000 at December 31, 2002.

Derivative Contracts - Comprised of a currency exchange contract, which is recorded at fair value on the accompanying consolidated balance sheets.

7.

CONCENTRATIONS OF CREDIT RISK

Credit Risk - Credit risk is the risk of loss the Partnership would incur if counterparties fail to perform their contractual obligations (including accounts receivable and due from affiliates). The Partnership primarily conducts business with customers in the energy industry, such as investor-owned utilities, energy trading companies, financial institutions, gas production

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companies and gas transportation companies located in the United States and Canada. This concentration of counterparties may impact the Partnership’s overall exposure to credit risk in that its counterparties may be similarly affected by changes in economic, regulatory or other conditions. The Partnership mitigates potential credit losses in accordance with established credit approval practices and limits by dealing primarily with counterparties it considers to be of investment grade.

     As of December 31, 2003, the Partnership’s credit risk is primarily concentrated with the following customers: Con Edison, Niagara Mohawk and the New York Independent System Operator, all of which are considered to be of investment grade.

8.

COMMITMENTS AND CONTINGENCIES

Power Purchase Agreements, Electricity - Prior to July 1, 1998, the Partnership had a power purchase agreement, as amended, with Niagara Mohawk for the sale of electricity. The agreement was for a twenty-year period terminating in April 2012. As a result of Niagara Mohawk’s restructuring of its power purchase agreements, on August 31, 1998, the Partnership and Niagara Mohawk signed an Amended and Restated Niagara Mohawk Power Purchase Agreement, effective July 1, 1998, for a term of ten years. The Amended and Restated Niagara Mohawk Power Purchase Agreement transfers dispatch decision-making authority from Niagara Mohawk to the Partnership. In effect, Unit 1 operates on a “merchant-like” basis, whereby the Partnership has the ability and flexibility to dispatch Unit 1 based on current market conditions.

     As part of the restructuring of Niagara Mohawk’s business including the Amended and Restated Niagara Mohawk Power Purchase Agreement, Niagara Mohawk paid the Partnership a net amount of approximately $8,308,000, which was recorded by the Partnership as deferred revenue. Both the deferred revenue and certain restructuring costs totaling approximately $1,233,000, are amortized over the term of the Amended and Restated Niagara Mohawk Power Purchase Agreement.

     The Partnership also has a power purchase agreement with Con Edison for an initial term of 20 years that began on September 1, 1994, the date Unit 2’s commercial operations commenced. The contract may be extended under certain circumstances.

     The Con Edison power purchase agreement provides Con Edison the rights to schedule Unit 2 for dispatch on a daily basis at full capability, partial capability or off-line. Con Edison’s scheduling decisions are required to be based in part on economic criteria which, pursuant to the governing rules of the New York Independent System Operator, take into account the variable cost of the electricity to be delivered. Certain payments under these agreements are unaffected by levels of dispatch. However, certain payments may be rebated or reduced to Con Edison if the Partnership does not maintain a minimum availability level.

Steam Sales Agreements - The Partnership has a steam sales agreement, as amended, with General Electric that has a term of 20 years from the commercial operations date of Unit 2 and may be extended under certain circumstances. Under the steam sales agreement, General Electric is obligated to purchase the minimum quantities of steam necessary for the Facility to

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maintain its Qualifying Facility status (Note 1). In the event General Electric fails to meet minimum purchase quantity, the Partnership may acquire title to the Facility site and terminate the operating lease agreement with General Electric at no cost to the Partnership.

     The agreement provides General Electric the right of first refusal to purchase the Facility, subject to certain pricing considerations. Additionally, General Electric has the right to purchase the boiler facility that produces steam at a mutually agreed upon price upon termination of the steam sale agreement. The steam sales agreement may be terminated by the Partnership with a one-year advanced written notice upon the termination of either Niagara Mohawk or Con Edison power purchase agreement, whichever is earlier. The steam sales agreement may also be terminated by General Electric with a two-year advanced written notice if General Electric’s plant no longer has a requirement for steam.

The Partnership has entered into various long-term firm commitments with approximate dollar obligations as follows (in thousands):

Site Lease -The Partnership has an operating lease agreement with General Electric. The amended lease term expires on August 31, 2014, and is renewable for the greater of five years or until termination of any power sales contract, up to a maximum of 20 years. The lease may be terminated by the Partnership under certain circumstances with the appropriate written notice during the initial term. The lease provides certain tracts of land for a fixed fee as well as provides for certain utilities and other services based on a fixed fee with annual escalation.

Fuel Supply and Transportation Agreements - The Partnership has a firm natural gas supply agreement, as amended, with Paramount Resources Ltd., a Canadian corporation, for Unit 1. The agreement has an initial term of 15 years that began November 1, 1992, with an option to extend for an additional four years upon satisfaction of certain conditions.

     The Partnership has firm natural gas supply agreements with various suppliers for Unit 2. The agreements have an initial term of 15 years beginning on November 1, 1994, and an option to extend for an additional five-year term upon satisfaction of certain conditions.

     Each Unit 2 natural gas supply contract requires the Partnership to purchase a minimum of 75% of the maximum annual contract volume every year. If the Partnership fails to meet this minimum quantity, the shortfall (the difference between the minimum required volume and the actual nomination) must be made up within the next two years. If the Partnership is not able to

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make up the shortfall within the next two years, the suppliers have the right to reduce the maximum daily contract quantity by the shortfall.

     The Partnership has three firm fuel transportation service agreements for Unit 1, each with a 20-year term commencing November 1, 1992.

     The Partnership has three firm fuel transportation service agreements for Unit 2, each with a 20-year term commencing November 1, 1994. Under one of these agreements, the fuel transporter has exercised its right to require the Partnership to post letters of credit on an annual basis. The Partnership has posted a letter of credit for approximately $2,925,000 U.S. dollars and two fuel suppliers, on behalf of the Partnership, have posted letters of credit totaling approximately $8,759,000 Canadian dollars. The Partnership is obligated to reimburse the fuel suppliers for all costs related to obtaining and maintaining the letters of credit.

Electric Transmission Agreements - The Partnership has a 20-year interconnection agreement with Niagara Mohawk to interconnect the power output from Unit 1 to Niagara Mohawk’s electric transmission system through April 16, 2012. The agreement may be extended if the power purchase agreement with Niagara Mohawk is extended.

     The Partnership has a 20-year firm transmission agreement with Niagara Mohawk to transmit the power output from Unit 2 to Con Edison through August 31, 2014. Co-terminus with this agreement, the Partnership has an interconnection agreement with Niagara Mohawk to interconnect the power output from Unit 2 to Niagara Mohawk’s electric transmission system.

Operation and Maintenance Agreement — The Partnership has an operations and maintenance services agreement with General Electric whereby General Electric provides certain operation and maintenance services to both Unit 1 and Unit 2 through December 31, 2007.

Water Supply Agreement - The Partnership has a 20-year take-or-pay water supply agreement with the Town of Bethlehem under which the Partnership is committed to purchase a minimum quantity of water supply annually. The agreement is subject to adjustment for changes in market rates beginning in October 2004.

Payment in Lieu of Taxes Agreement - In October 1992, the Partnership entered into a PILOT agreement with the Town of Bethlehem Industrial Development Agency (“IDA”), a corporate governmental agency, which exempts the Partnership from certain property taxes. The agreement commenced on January 1, 1993, and will terminate on December 31, 2012. PILOT payments are due semi-annually.

Other Contingencies - The Partnership is a party in various legal proceedings and potential claims arising in the ordinary course of its business. Management does not believe that the resolution of these matters will have a material adverse effect on the Partnership’s consolidated financial position or results of operations.

     On November 6, 2001, the Partnership received from the New York State Department of Environmental Conservation (“DEC”) the Facility’s Title V operating permit endorsed by the DEC on November 2, 2001 (the “Title V Permit”). The Title V Permit as received by the Partnership contains conditions that conflict with the Partnership’s existing air permits, and the

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Facility’s compliance with these conditions under certain operating circumstances would be problematic. Further, the Partnership believes that certain of the conditions contained in the Title V Permit are inconsistent with the laws and regulations underlying the Title V program and Title V operating permits issued by the DEC to comparable electric generating facilities in New York. By letter dated November 12, 2001, the Partnership has filed with the DEC a request for an adjudicatory hearing to address and resolve the issues presented by the Title V Permit, and the terms and conditions of the Title V Permit will be stayed pending a final DEC decision on the appeal. At this time, the Partnership cannot assess whether a settlement can be achieved, the likely outcome of the adjudicatory hearing if no settlement is achieved, or the impact on the Facility.

9.

RELATED PARTIES

     JMCS I Management manages the day-to-day operation of the Partnership and is compensated at agreed-upon billing rates that are adjusted quadrennially in accordance with an administrative services agreement. The cost of services provided by JMCS I Management are included in administrative services — affiliates in the accompanying consolidated statements of operations. The total amount due to JMCS I Management at December 31, 2003, was approximately $181,000.

     The Partnership purchases from and sells gas to affiliates of JMC Selkirk. As of March 18, 2003, PG&E Energy Trading, Canada Corporation (“ET Canada”) ceased to be a related party and, as of May 31, 2003, the Partnership ceased transactions with NEGT Energy Trading — Gas. Gas purchases are recorded as fuel costs and sales of gas are recorded as fuel revenues in the accompanying consolidated statements of operations. There were no amounts due to/from ET Canada or NEGT Energy Trading — Gas at December 31, 2003. At December 31, 2003, the total amount due to Pittsfield Generating Company, L.P. (“Pittsfield Generating”) was approximately $146,000 and the net amount due from MASSPOWER was approximately $24,000.

Gas purchased from affiliates is as follows (dollars in thousands):

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Gas sold to affiliates is as follows (dollars in thousands):

     In May 1996, the Partnership entered into an enabling agreement with NEGT Energy Trading — Power, an affiliate of JMC Selkirk, to purchase and sell electric capacity, electric energy, and other services. As of May 31, 2003, the Partnership ceased transactions with NEGT Energy Trading — Power. There were no sales of energy, capacity and other services pursuant to this enabling agreement for the year ended December 31, 2003, as compared to approximately $2,264,000 in 2002 and approximately $3,878,000 in 2001. There was no amount due from NEGT Energy Trading — Power at December 31, 2003.

     The Partnership has two agreements with Iroquois Gas Transmission System (“IGTS”), an affiliate of JMC Selkirk to provide firm transportation of natural gas from Canada. Firm fuel transportation services for the year ended December 31, 2003 totaled approximately $7,080,000, compared to approximately $7,456,000 in 2002 and approximately $7,741,000 in 2001. These services are recorded as fuel costs in the accompanying consolidated statements of operations. The total amount due to IGTS for firm transportation at December 31, 2003, was approximately $616,000.

* * * * * *

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