ITEM 1. BUSINESS - ----------------
General	
	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 to sell electric capacity and energy produced by the Facility to Niagara Mohawk Power Corporation ("Niagara Mohawk") and Consolidated Edison Company of New York, Inc. ("Con Edison") and steam produced by the Facility to GE Plastics, a core business of General Electric Company ("General Electric"). See "The Facility and Certain Project Contracts, Niagara Mohawk" in this report for a discussion of certain developments related to the restructuring of the Partnership's Niagara Mohawk Power Purchase Agreement.
	Selkirk Cogen Funding Corporation (the "Funding Corporation"), a Delaware corporation, was organized in April 1994 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 One Bowdoin Square, Boston Massachusetts 02114. The telephone number is (617) 227-8080.
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 Cogen Technologies Selkirk GP, Inc. ("Cogen Technologies 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., formerly known as JMCS I Investors, L.P. ("Investors"), EI Selkirk, Inc. ("EI Selkirk") and Cogen Technologies Selkirk, L.P. ("Cogen Technologies 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, Cogen Technologies 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 J. Makowski Company, Inc. ("J. Makowski Company"), and JMCS I Management is a direct, wholly-owned subsidiary of J. Makowski Company. J. Makowski Company develops, manages and owns interests in gas-fired electric generating facilities and natural gas supply and transportation projects. In August 1994, a controlling interest in J. Makowski Company was acquired by a special purpose corporation jointly owned by PG&E Generating Company, a subsidiary of PG&E Enterprises, and Bechtel Generating Company, a subsidiary of Bechtel Enterprises, Inc. Investors is a limited partnership of JMCS I Holdings, Inc., JMC Selkirk, Inc. (each an affiliate of J. Makowski Company) and TPC Generating, Inc.
	Cogen Technologies GP and Cogen Technologies LP are each affiliates of Cogen Technologies, Inc. ("Cogen Technologies"). Cogen Technologies has developed and owns interests in electric generating facilities.
	EI Selkirk is a wholly-owned subsidiary of GPU International, Inc. ("GPUI", formerly known as Energy Initiatives, Inc.) which in turn is a wholly-owned subsidiary of GPU, Inc. (formerly known as General Public Utilities Corporation), a registered electric utility holding company under the Public Utility Holding Company Act of 1935, as amended ("PUHCA"). GPUI is actively engaged in the business of developing, owning and/or operating domestic and foreign independent power generation projects.
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") for its own account 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 financing its outstanding indebtedness and the remaining proceeds were loaned to the Partnership (the total amount of such extensions of credit, the "Partnership Loans"). Subsequently, in November 1994, the Funding Corporation and the Partnership offered to exchange (i) $165,000,000 of 8.65% First 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 8.9 8% 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, J. Makowski Company, TPC Generating, Inc., PG&E Enterprises, Bechtel Enterprises, Inc., Cogen Technologies, GPUI 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 of Cogen Technologies GP of the outstanding capital stock of each such General Partner.
The Facility and Certain Project Contracts
The Facility
	The Facility is located on an approximately 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 Faci lity uses natural gas as its primary fuel input to produce electric energy for sale to Niagara Mohawk and Con Edison 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, 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 PUR PA and the regulations promulgated thereunder by the Federal Energy Regulatory Commission ("FERC").
Niagara Mohawk
	On October 6, 1995, Niagara Mohawk filed its "PowerChoice" proposal with the New York State Public Service Commission ("NYPSC"). On October 12, 1995, Niagara Mohawk filed a Report on Form 8-K with the Securities and Exchange Commission (the "Commission") explaining the PowerChoice proposal (the "PowerChoice Statement"). In the PowerChoice Statement, Niagara Mohawk describes a number of related proposals to restructure the utility's business, including the reorganization of its assets and the renegotiation of its contracts with generators which, like the Partnership, are not regulated as utilities ("non-utility generators"). In connection with PowerChoice, Niagara Mohawk filed a Report on Form 8-K on March 10, 1997 with the Commission in which it announced an agreement in principle to restructure or terminate 44 power purchase contracts. Among the contracts which is proposed to be restructured is the Niagara Mohawk Power Purchase Agreement for the electric output of Unit 1. Pursuant to the agreement in p rinciple and subject to negotiation as described below, the parties propose to restructure the Niagara Mohawk Power Purchase Agreement to provide for payments from Niagara Mohawk which may be under one or more pricing arrangements for up to 12 years in lieu of the rates which would be payable under the current Niagara Mohawk Power Purchase Agreement.
	The details of the price arrangements as well as other possible contract modifications are yet to be negotiated, and implementation of the agreement in principle is subject to a number of significant conditions, including execution of binding agreements; any requisite corporate, partnership and shareholder approvals; NYPSC approval of the agreement in principle and other related transactions; other state and federal approvals; the resolution of all tax issues; and obtaining required amendments or waivers under existing credit agreements and third-party contracts, including, with respect to the Partnership, satisfying certain standards under the Indenture relating to the absence of material adverse changes and the maintenance of required projected debt service coverage ratios or receiving any required approval of holders of the Bonds or other creditors.
	The Partnership, as a party to the agreement in principle, is committed to negotiate to reach agreement on a restructured power purchase agreement; however, the Partnership expresses no opinion with respect to the likelihood that all of the conditions to implementation of the agreement in principle will be met or that all of the other elements of PowerChoice will be realized. Further, the Partnership expresses no opinion with respect to the viability of Niagara Mohawk's proposed alternatives should PowerChoice fail, such as Niagara Mohawk's proposal to take possession of independent power projects through the power of eminent domain and to thereafter sell such projects or Niagara Mohawk's position that it has not ruled out the ultimate possibility of a filing for restructuring under Chapter 11 of the U.S. Bankruptcy Code as set forth in the PowerChoice Statement. Nevertheless, in the absence of agreement on a definitive restructured power purchase agreement, the Partnership continues to believe that the Niagara Mohawk Power Purchase Agreement is a valid and binding contract with Niagara Mohawk. Until negotiations on the restructured power purchase agreement advance further, the Partnership will not be able to determine what effect, if any, the restructured power purchase agreement or the PowerChoice proposal will have on the Partnership, its business or net operating revenues. For the year ended December 31, 1996, electric sales to Niagara Mohawk accounted for approximately 17.1% of total project revenues.
	As a result of the announcement of the agreement in principle, Standard & Poor's has placed the Bonds on credit watch "with negative implications," based in part on its analysis of Form 8-K recently filed by Niagara Mohawk and the Partnership, respectively and its belief that the restructuring has the potential to erode cash flow coverage derived from long-term contracts supporting the Bonds. As of the date of this report, Moody's Investors Service has not changed its rating or its "negative outlook" on the Bonds.
	Unit 1 commenced commercial operation on April 17, 1992 and is selling at least 79.9 MW of electric capacity and associated energy to Niagara Mohawk under the current long-term contract that allows Niagara Mohawk to schedule Unit 1 for dispatch on an economic basis (the "Niagara Mohawk Power Purchase Agreement"). The term of the Niagara Mohawk Power Purchase Agreement is 20 years from the date of initial commercial operation of Unit 1. The Niagara Mohawk Power Purchase Agreement provides for four payment components: (i) a capacity payment, (ii) an energy payment, (iii) a transportation payment and (iv) an operation and maintenance ("O&M") payment. The capacity payment and portions of the transportation and O&M payments are fixed charges to be paid whether or not Unit 1 is dispatched on-line, subject, in the case of the capacity payment, to certain discounts and rebates in accordance with the Niagara Mohawk Power Purchase Agreement. The energy payment and portions of the transportation and O&M payments are variable charges based on electricity produced by Unit 1 and delivered to Niagara Mohawk. Pursuant to an agreement which, in part, amends and supplements the Niagara Mohawk Power Purchase Agreement, the Partnership and Niagara Mohawk have agreed that the 10% reduction in the Partnership's rates which would otherwise be triggered under the Niagara Mohawk Power Purchase Agreement as a result of Unit 1's exceeding the 80 MW output limitation imposed on a New York State co-generation facility will not apply to the Partnership, subject to the receipt of any regulatory approvals or the adoption of any legislation that may be required. Niagara Mohawk and the Partnership have subsequently confirmed that no additional regulatory approvals or legislation is necessary, and have agreed that Unit 1 may exceed the 80 MW limit during specific transactions authorized by Niagara Mohawk. As of the date of this report, the Partnership has sold output in excess of 80 MW from Unit 1 only to Niagara Mohawk.
	Niagara Mohawk owns, operates and maintains interconnection facilitie 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 Niagara Mohawk's power grid, no transmission services are required for the delivery of power under the Niagara Mohawk Power Purchase Agreement. 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. The Partnership does not expect a restructuring of the Niagara Mohawk Power Purchase Agreement to have any effect on Unit 2 transmission services provided by Niagara Mohawk.
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 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 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 p ayment 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. For the year ended December 31, 1996 electric sales to Con Edison accounted for approximately 67.2% of total project revenues.
	Con Edison by a letter dated September 19, 1994 claimed the right to acquire that portion of Unit 2's firm natural gas supply not used in operating Unit 2, when Unit 2 is dispatched off-line or at less than full capability. The Con Edison Power Purchase Agreement contains no express language granting Con Edison any rights with respect to such excess natural gas. Nevertheless, Con Edison has argued that, since payments under the contract include fixed fuel charges which are payable whether or not Unit 2 is dispatched on-line, Con Edison is entitled to take delivery of any excess natural gas. The Partnership vigorously disputes the position adopted by Con Edison, based notably on the absence of any contractual provision according Con Edison the claimed rights but also on the fact that the Partnership has assumed the risk under the Con Edison Power Purchase Agreement that the fuel charges payable by Con Edison are insufficient to cover the costs actually incurred by the Partnership. By a letter dated May 23 , 1995, Con Edison indicated its intention to pursue the claim asserted in the September 19, 1994 letter. In the May 23, 1995 letter, Con Edison reserved the right to claim 100% of the margins derived from the sales of Unit 2's firm natural gas supply not used in operating Unit 2 (non-plant gas sales) and requested that the Partnership reduce the monthly amount invoiced to Con Edison by 50% of a calculated value of the non-plant gas sales. The Partnership strenuously objected to Con Edison's contentions and, at a meeting between the
Partnership and Con Edison, Con Edison agreed to continue not to deduct any amount attributable to non-plant gas sales from payments made upon monthly invoices but stated it would do so under protest, pending further discussions between the parties. Since the commencement of commercial operations of Unit 2, the Partnership made and continues to make, from time to time, excess gas lay-off sales from Unit 2's gas supply. The Partnership does not intend to adjust the monthly in voices issued to Con Edison and continues to assert that Con Edison is not entitled to any revenues or margins derived from non-plant gas sales. In the event Con Edison were to pursue its asserted claim, the Partnership would expect to pursue all available legal remedies, but there can be no certainty that the outcome of such remedial action would be favorable to the Partnership or, if favorable, would provide for the Partnership's full recovery of its damages.
	The Partnership's cash flows from the sale of electric output would be materially and adversely affected if Con Edison were to prevail in its claim to Unit 2's excess natural gas volumes and the related margins.
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 has informed the Partnership of its intent to implement an energy efficiency project in 1997 that would reduce the quantity of steam required by the GE Plant. Under the energy efficiency project, General Electric anticipates managing its annual average steam demand at 160,000lbs/hr. If General Electric is able to manage its annual average steam demand at 160,000lbs/hr then the Partnership's steam revenues would be reduced to the nominal amount General Electric is charged for the annual equivalent of 160,000lbs/hr. For the year ended December 31, 1996 steam sales to General Electric accounted for approximately 1.6% of total project revenues. The energy efficient 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.
Unit 1 Gas Supply and Transportation
	To supply natural gas needed to operate Unit 1, the Partnership entered in to 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 "Paramount Contract"). The Paramount Contract requires Paramount to maintain a level of recoverable reserves and deliverability from its dedicated reserves through the term of the 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, Iroquois Gas Transmissions System, L.P. and Tennessee Gas Pipeline Company. Each of the Unit 1 Gas Transportation Contracts has a term of 20 years beginning November 1, 1992. Either the Partnership (at Niagara Mohawk's direction or on its own initiative) or Paramount may require renegotiation, not more frequently than annually, of the commodity charge and/or method of escalation and, failing agreement (including Niagara Mohawk's concurrence), these pricing issues may be submitted to arbitration binding on the Partnership, Paramount and Niagara Mohawk. The Paramount Contract establishes an arbitration and renegotiation procedure which coordinates with the Niagara Mohawk Power Purchase Agreement. The Partnership cannot, at this time, determine what effect, if any, a restructuring of the Niagara Mohawk Power Purchase Agreement will have on the volumes and pricing of natural gas purchases under the Paramount Contract or whether modifications to the terms of this contract will be required in conjunction with any restructuring of the Niagara Mohawk Power Purchase Agreement.
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, PanCanadian Petroleum Limited and Producers Marketing Ltd. (formerly known as 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 Pipelines Limited, Iroquois Gas Transmissions System, L.P. and Tennessee Gas Pipeline Company. Each of the Unit 2 Gas Transportation Contracts has a term of 20 years beginning November 1, 1994.
Fuel Management
	The Partnership, through the Project Management Firm, manages the Facility's fuel arrangements. The Partnership attempts to direct 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 the scheduled deliveries of electricity to Niagara Mohawk and Con Edison. In addition, the Partnership endeavors to take advantage of market opportunities, as available, 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 opportunities include resales of excess natural gas supplies ("gas resales") when Unit 1 or Unit 2 is dispatched off-line or at less than full capacity, and "peak shaving" arrangements 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 num ber 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 No. 2 fuel oil or, if available, interruptible natural gas supplies. 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 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 and peak shaving sales by entering into agreements for interruptible transportation service. In m anaging Unit 2's fuel arrangements, the Partnership, through the Project Management Firm, 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.
	Unit 1 and Unit 2 have the capability to operate on No. 2 fuel oil and are able 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 one million gallons of fuel oil, a supply sufficient to run all three gas turbines constituting the Facility for approximately one and a half days at full capacity without refilling. The Partnership purchases fuel oil on a spot basis. The Facility Site is approximately five miles from the Port of Albany, New York, a major oil terminal area. In addition, several major oil companies supply No. 2 fuel oil in the Albany area through leased storage or throughput arrangements. Fuel oil is transported to the Facility by truck.
Customers/Competition
	Niagara Mohawk is an investor-owned utility engaged in the production, 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 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.
	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 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 long-term contracts to sell electric generating capacity and energy from the Facility to Niagara Mohawk and Con Edison; therefore, subject to the effect of any restructured Niagara Mohawk Power Purchase Agreement it does not expect competitive forces tohave a significant effect on its business. Nevertheless, each of these Power Purchase Agreements permits the purchasing utility to schedule the Unit for dispatch on an economic basis, which takes into account the variable cost of electricity to be delivered by the Unit compared to the variable cost of electricity available to the purchasing utility from other sources. Accordingly, competitive forces may have some effect on the Facility's dispatch levels. Furthermore, if and when the restructured Niagara Mohawk Power Purchase Agreement goes into effect, the Partnership would anticipate marketing, under certain conditions, the electric output of Unit 1 to purchasers other than Niagara Mohawk based on market conditions then in effect. The Partnership cannot, at this time, determine what effect, if any, the impact of such competitive sales will have on the Partnership' s financial condition or 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 producer's customer demand results in the Facility's dispatch being somewhat affected by seasonality. Niagara Mohawk's residential customer demand peaks during the colder winter months due to customer reliance on electric heat, and Con Edison's commercial customer demand peaks during the warmer summer months due to customer reliance on air conditioning in office buildings. 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 stream 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.
	While the NYPSC has specifically authorized Unit 1 and Unit 2 to be thermally integrated, the NYPSC has stated that Unit 1 and Unit 2 may not be electrically interconnected (i.e., the net electrical output of Unit 1's gas turbine and steam turbine must be dedicated to the Niagara Mohawk Power Purchase Agreement and the net electrical output of Unit 2's turbines and steam turbine must be dedicated to the Con Edison Power Purchase Agreement).
	All regulatory approvals currently required to operate the combined Facility have been obtained. The Partnership is subject to federal, state, and local laws and regulations pertaining to air and water quality, and other environmental matters. 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 accomplished, whether modifications of the Facility will be required or, generally, what effect existing or future statutory action may have upon Partnership operations.
	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 operating permit and submit an application to the DEC for the same prior to June 9, 1997. 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.
	In December 1995, the Partnership received a letter from the EPA requesting revision of periodic air emission reporting to the Agency. The Partnership tendered an interim response to the inquiry in January 1996. Although mutual consensus regarding a reporting format is anticipated, the Partnership cannot determine what, if any, actions could potentially be taken by the EPA.
	In January 1997, the Partnership received a letter from the EPA indicating that the Agency completed its statutorily required review of the Facility's Facility Response Plan ("FRP"), as submitted to the EPA in September of 1994 pursuant to the codified requirements of the Oil Pollution Control Act of 1990. Accompanying this letter the Partnership received a listing of requested administrative revisions to the FRP. In February 1997 the Facility underwent an FRP field inspection and in March 1997, the Partnership received a letter from the EPA indication that there were no "site specific violations" identified during the field inspection. Although mutual consensus regarding the administrative revisions to, and format of, the Facility's FRP is anticipated, the Partnership cannot determine what, if any, actions could potentially be taken by the EPA.
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 ten site employees and support personnel in its Boston and Bethesda offices, who manage Unit 1 and Unit 2 on a combined basis. 	 	General Electric through its O&M Services component (the "Operator") provides operation and maintenance services for the Facility pursuant to an Amended and 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 32 employees to operate the Facility.
ITEM 2.
ITEM 2. PROPERTIES - -------------------
	The Facility is located in the Town of Bethlehem, County of Albany, New York, on approximately 15.7 acres of land (the "Facility Site") leased by the Partnership from General Electric. In addition, the Partnership laterally owns an approximately 2.1 mile pipeline which 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.
ITEM 3. LEGAL PROCEEDINGS - ----------------------------
	The Partnership is party to the legal proceedings described below.
Gas Transportation 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. Currently pending proceedings primarily relate to filings made by Tennessee Gas Pipeline Company ("Tennessee") seeking changes to its operating terms and conditions, rate adjustments and authority to collect additional costs for gas transportation services. However, the Partnership has entered into a settlement with Tennessee, subject to FERC approval, that will resolve a substantial number of these proceedings.
Curtailment
	In August 1992, Niagara Mohawk filed a petition requesting the NYPSC to authorize Niagara Mohawk to curtail purchases from, and avoid payment obligations to, non-utility generators, including Qualifying Facilities such as the Facility during certain periods. Niagara Mohawk claimed that such curtailment would be consistent with PURPA, and the regulations promulgated thereunder, which contemplates utilities' curtailing purchases from Qualifying Facilities under certain circumstances. In October 1992, the NYPSC initiated a proceeding to investigate whether conditions existed justifying the exercise of the PURPA curtailment rights and, if so, to determine the procedures for implementing PURPA curtailment rights. Con Edison also filed a petition in this proceeding seeking to implement PURPA curtailment rights during certain periods. An administrative law judge appointed by the NYPSC held hearings during the spring of 1993, however, his opinion was never released. On August 30, 1996 the NYPSC reopened the curtailment proceedings and directed an administrative law judge to prepare a recommended decision under an abbreviated deadline. In light of Niagara Mohawk reaching agreement in principle to restructure or terminate 44 power purchase contracts (see Part I Item 1. Business- The Facility and Certain Project Contracts- Niagara Mohawk for discussion of the agreement in principle), the NYPSC did not present a ruling in the case. The Partnership expects that any agreement which it enters into with Niagara Mohawk to implement the agreement in principle will waive Niagara Mohawk's right, if any, to curtail purchases from the Partnership.
	In any event, the Partnership has taken the position in this proceeding that it should not be subject to curtailment as a result of this proceeding , even if the NYPSC grants Niagara Mohawk and Con Edison some measure of generic curtailment rights. The Partnership's position is based in part on the fact that neither Niagara Mohawk nor Con Edison bargained for an express curtailment right in its Power Purchase Agreement and the Partnership agreed to permit Niagara Mohawk and Con Edison to direct the dispatch of the relevant Unit. Nevertheless, both Niagara Mohawk and Con Edison have refused to expressly waive their claimed curtailment rights against dispatchable facilities and have not agreed to exem pt the Facility from curtailment, notwithstanding the absence of contractual language in the Power Purchase Agreements granting the utilities this right. If Niagara Mohawk and Con Edison were to receive NYPSC authorization to curtail power purchases from Qualifying Facilities including dispatchable facilities, they may seek to implement curtailment with respect to the Partnership by avoiding not only energy payments but also capacity payments during periods in which the Facility is curtailed. Such a reduction in energy payments and capacity payments could materially and adversely affect the Partnership's net operating revenues.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - ------------------------------------------------------------
	None.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER - ----------------------------------------------------------------------------- MATTERS - ------- 	 	There is no established public market for Funding Corporation's common stock. The 10 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 of the Partnership is held by the Partners and, therefore, there is no established public market for the Partnership's common equity.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA - --------------------------------
	From its inception in December 1989 until Unit 1 commenced commercial operation in April 1992, the Partnership was in the development stage. Accordingly, no results of operation information is presented for fiscal year 1992. Unit 1 and Unit 2 began commercial operations on April 17, 1992 and September 1, 1994, respectively. The selected financial data set forth below should be read in conjunction with the financial statements, related notes and other financial information included elsewhere herein.
						 Year Ended Nine Months Ended	 				 December 31, 	 December 31, 						 ----------------------------	 ----------------- 				 1996 1995 1994 1994 1993 						 ----		 ----		 ----		----	 ---- (in thousands)
Statement of Operations Data: Operating revenues $174,442 $155,778 $ 72,707 $ 61,450 $ 32,839 Cost of revenues	 119,747 114,491 52,331 44,238 26,430 Other operating expenses	 6,669 7,174 5,009 4,090 2,944 Operating income	 48,026 34,113 15,367 13,122 3,465 Net interest expense		 32,844 32,392 17,094 14,621 7,504 Write-off of deferred finance charges and interest rate hedge --- --- 34,885 34,885 --- 						-------- --------- ---------	 ---------	--------- Net income (loss)	 $ 15,182 $ 1,721 $(36,612) $(36,384) $ (4,039) 					 -------- --------- --------- --------- --------- 						-------- --------- --------- --------- ---------
			 	 December 31, March 31, 							 ----------------------- ---------------- 			 	 1996 1995	 1994 	 1994 1993 							 ---- ---- ---- ---- ---- 						 (in thousands)
Balance Sheet Data: Plant and equipment (net) 	 $334,229 $346,285 $354,440 $ 90,083 $ 93,372 Construction work-in-progress	 --- --- --- 225,171 104,939 Total assets		 401,454 416,080 441,555 347,757 227,893 Long-term debt and bonds 389,253 391,420 392,000 332,929 217,227 Partners' capital	 (18,810) 1,530 20,821 360 4,627
Supplementary Financial Information
	The following is a summary of the quarterly results of operations for the nine months ended December 31, 1994 and the years ended December 31, 1995 and December 31, 1996.
			 	 Three Months Ended (unaudited) 						 -------------------------------------------------- 			 March 31 June 30 September 30 December 31 						 --------		 -------	------------ ----------- 											(in thousands) Nine Months Ended December 31, 1994 - -------------------- Operating revenues $ 10,392 $ 15,646 $ 35,412 Gross profit 	 2,327 4,913 9,972 Net income (loss) (35,824) (465) (95)
Year Ended December 31, 1995 - --------------------- Operating revenues $ 39,130 $ 39,437 $ 37,349 $ 39,862 Gross profit 	 	 10,640 9,771	 9,626	 11,250 Net income (loss) 523 (168) 7	 1,359
Year Ended December 31, 1996 - -------------------- Operating revenues $ 46,405 $ 42,109	 $ 41,139	 $ 44,789 Gross Profit			 16,572 12,276 11,569 14,278 Net income (loss)	 6,275 2,491 1,716	 4,700
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND - ----------------------------------------------------------------------------- RESULTS OF OPERATIONS - ---------------------
Overview
	The Partnership owns a natural gas-fired, combined-cycle cogeneration facility consisting of two units, with revenues derived primarily from sales of electricity and, to a lesser extent, from sales of steam and natural gas. Unit 1 and Unit 2 began commercial operations on April 17, 1992 and September 1, 1994, respectively. The Partnership had improved operating results in 1996, due principally to increased electric and gas resale revenues. During 1996, approximately $35.5 million was released for distribution to the partners.
Results of Operations
Year Ended December 31, 1996 Compared to the Year Ended December 31, 1995
	The Partnership earned net income of $15.2 million for the year ended December 31, 1996 as compared to net income of $1.7 million for the corresponding period in the prior year. The increase in net income is due primarily to the increase in electric and gas resale revenues which was primarily due to increased dispatch and capacity of Unit 1, higher contract energy rates due to higher fuel index prices for Unit 2 and an increase in average natural gas resale prices.
	Total revenues for the year ended December 31, 1996 were approximately $174.4 million as compared to approximately $155.8 million for the corresponding period in the prior year.
Electric Revenues (dollars and kWh's in millions):
					 For the Year Ended December 31, 1996 December 31, 1995 		 ---------------------------------- -------------------------------- 	 Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch ------- ----- -------- -------- ------- ----- -------- -------- Niagara Mohawk 29.9 303.1 44.81% 54.50% 27.5 293.6 41.95% 44.13% Con Edison 117.2 1,622.7 69.71% 87.61% 110.1 1,781.1 76.69% 85.42%
	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 by each Units power purchaser (regardless of output level) in a given time period expressed as a percentage of the total number of hours in that time period.
	Revenues from Niagara Mohawk increased $2.4 million for the year ended December 31, 1996 as compared to the corresponding period in the prior year. Energy delivered to Niagara Mohawk was sold primarily at full contract rates for the year ended December 31, 1996, whereas energy delivered to Niagara Mohawk during the twelve months ended December 31, 1995 was primarily sold under special dispatch arrangements. During 1995, the Partnership frequently entered into special dispatch arrangements with Niagara Mohawk, at times when the Unit would have otherwise been dispatched off line, which called for the pricing of delivered energy at variable rates less than full contract rates. Revenues for energy delivered pursuant to special dispatch arrangements with Niagara Mohawk for the year ended December 31, 1996 were approximately $29.0 thousand as compared to approximately $5.1 million for the prior year. Revenues for the year ended December 31, 1996 were also favorably impacted by increased energy deliveries to Nia gara Mohawk, as evidenced by the 2.9% increase in the capacity factor from December 31, 1995 to December 31, 1996.
	Revenues from Con Edison increased $7.1 million for the year ended December 31, 1996 as compared to the corresponding period in the prior year. The increase in revenues is primarily attributable to all delivered energy during the year ended December 31, 1996 being sold at full contract rates and higher contract energy rates resulting from higher index fuel prices as compared to the corresponding period in the prior year. During the twelve months ended December 31, 1996, energy delivered to Con Edison was sold entirely at full contract rates, whereas for the majority of January 1995 and for a few days in February and April 1995, the Partnership entered into special dispatch arrangements with Con Edison, at times when the Unit would have otherwise been dispatched off line. These special dispatch arrangements called for the pricing of delivered energy at variable rates less than full contract rates. Revenues for energy delivered pursuant to special dispatch arrangements with Con Edison for the year ended December 31, 1995 was approximately $1.8 million. The increase in revenues for the year ended December 31, 1996 was partially offset by a decrease in energy deliveries, as evidenced by the 7.0% decrease in the capacity factor from December 31, 1995 to December 31, 1996. The decrease in energy deliveries was primarily due to a decrease in capacity during off-peak periods.
	Steam revenues for the year ended December 31, 1996 were approximately $2.7 million on 1,867.330 million pounds of steam delivered as compared to approximately $2.0 million on 1,718.101 million pounds of steam delivered for the corresponding period in the prior year. Revenue per unit of steam increased during the year ended December 31, 1996 as compared to the corresponding period in the prior year. Higher index fuel pricing and colder than normal winter months were the primary factors contributing to the increase in steam revenues for the twelve months ended December 31, 1996 as compared to the corresponding period in the prior year. Additionally, steam revenues for the year ended December 31, 1996 include an annual true-up of $0.2 million in favor of the steam host.
	Gas resale revenues for the year ended December 31, 1996 were approximately $24.6 million on sales of approximately 7.9 million MMBtu's as compared to approximately $16.1 million on sales of approximately 8.0 million MMBtu's for the corresponding period in the prior year. The $8.5 million increase in gas resale revenues during the year ended December 31, 1996 as compared to the corresponding period in the prior year is primarily due to an increase in average natural gas resale prices. The increase in average natural gas resale prices generally resulted from the colder than normal temperature this past winter which caused an increase in demand for natural gas and resulted in lower than normal gas storage levels. The decrease in gas resale volumes is attributable to the increase in the capacity factor for Unit 1 sales to Niagara Mohawk. The Partnership entered into gas resales during periods when Units 1 and 2 were not operating at full capacity.
	Fuel costs for the year ended December 31, 1996 were approximately $89.2 million on purchases of approximately 28.1 million MMBtu's as compared to approximately $84.7 million on purchases of 30.2 million MMBtu's for the corresponding period in the prior year. The increase in the cost of fuel was primarily due to higher contract firm fuel rates from higher index fuel prices and rate increases under the firm transportation contracts. The 2.1 million MMBtu decrease for the year ended December 31, 1996 as compared to the corresponding period in the prior year is primarily due to the negotiated temporary reduction in the maximum daily quantity and related transportation under the Unit 1 Paramount Contract.
	Operating and maintenance expenses for the year ended December 31, 1996 were approximately $17.9 million as compared to approximately $17.2 million for the corresponding period in the prior year. The $0.7 million increase in operating and maintenance expenses during the year ended December 31, 1996 as compared to the corresponding period in the prior year was due to an increase in maintenance of the Facility.
	Total other operating expenses, excluding amortization of deferred financing charges, for the year ended December 31, 1996 were approximately $5.5 million as compared to approximately $6.0 million for the corresponding period in the prior year. The decrease in other operating expenses was primarily due to an overall reduction in third party legal and consulting services.
	Amortization of deferred financing charges for the year ended December 31, 1996 was comparable to the corresponding period in the prior year. Deferred financing charges are amortized using the effective interest method.
	Net interest expense for the year ended December 31, 1996 was approximately $32.8 million as compared to approximately $32.4 million for the corresponding period in the prior year. The increase in net interest expense is primarily attributable to approximately a $0.5 million decrease in interest income for the year ended December 31, 1996 as compared to the corresponding period in the prior year. 									
Year Ended December 31, 1995 Compared to the Year Ended December 31, 1994
	The Partnership earned net income of $1.7 million for the year ended December 31, 1995 as compared to a net loss of $36.6 million for the corresponding period in the prior year. The increase in net income is due primarily to the commencement of Unit 2 commercial operations on September 1, 1994 and the $34.9 million aggregate write-off of deferred financing charges and interest swap breakage costs in connection with the refinancing of the Partnership's debt in May 1994. Unit 2 was operational for the entire year ended December 31, 1995 and only operational for four months during the year ended December 31, 1994. Net loss before write-off of deferred financing charges and swap breakage costs for the year ended December 31, 1994 was $1.7 million as compared to net income of $1.7 million for the year ended December 31, 1995.
	Total revenues for the year ended December 31, 1995 were approximately $155.8 million as compared to $72.7 million for the corresponding period in the prior year.
Electric Revenues (dollars and kWh's in millions):
					 For the Year Ended December 31, 1995 December 31, 1994 		 ---------------------------------- -------------------------------- 	 Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch ------- ----- -------- -------- ------- ----- -------- -------- Niagara Mohawk 27.5 293.6 41.95% 44.13% 26.8 218.8 37.01% 37.04% Con Edison 110.1 1,781.1 76.69% 85.42% 29.3 291.6 37.55% 49.00%
	Revenues from Niagara Mohawk increased $0.7 million for the year ended December 31, 1995 as compared to the corresponding period in the prior year. though capacity and dispatch for Unit 1 increased 4.9% and 7.1%, respectively for the year ended December 31, 1995 as compared to the corresponding period in the prior year, revenues did not increase proportionately because the Partnership entered into special dispatch arrangements with Niagara Mohawk for the majority of 1995 which called for the pricing of delivered energy at variable rates less than full contract rates. The Partnership entered into these special dispatch arrangements with Niagara Mohawk after determining that Unit 1 would likely have been dispatched off-line for much of the period due to the combined effect of low demand associated with unusually mild weather and the addition of new electric generation capacity further exacerbating the excess generation capability existing in the New York Power Pool. While the special dispatch pricing wa s at variable rates less than full contract, the Partnership received variable payments for the energy delivered to Niagara Mohawk under these arrangements which exceeded its associated variable costs of energy and increased net income from operations above what it would have been if Unit 1 had been dispatched off-line during these periods. Revenues for energy delivered pursuant to special dispatch arrangements with Niagara Mohawk for the year ended December 31, 1995 were $5.1 million as compared to $0.2 million for the corresponding period in the prior year.
	Revenues from Con Edison increased $80.8 million for the year ended December 31, 1995 as compared to the corresponding period in the prior year. The increase in revenues is due to the commencement of Unit 2 commercial operations on September 1, 1994. Unit 2 was operational for the entire year ended December 31, 1995 and only operational for four months during the year ended December 31, 1994. The Partnership entered into special dispatch arrangements with Con Edison which called for the pricing of delivered energy at variable rates less than full contract rates during three months of 1995 and two months of 1994. While the special dispatch pricing was at variable rates less than full contract, the Partnership received variable payments for the energy delivered to Con Edison under these arrangements which exceeded its associated variable costs of energy and increased net income from operations above what it would have been if Unit 2 had been dispatched off-line during these periods. Revenues for energy d elivered pursuant to special dispatch arrangements with Con Edison for the year ended December 31, 1995 were $1.8 million as compared to $0.7 million for the corresponding period in the prior year.
	Steam revenues for the year ended December 31, 1995 were approximately $2.0 million on 1,718.101 million pounds of steam delivered as compared to approximately $5.0 million on 2,062.827 million pounds of steam delivered for
the corresponding period in the prior year. Revenue per unit of steam decreased during the year ended December 31, 1995 as compared to the corresponding period in the prior year, because, effective with the commercial operations of Unit 2, the pricing provisions of the Steam Sales Agreement, changed, resulting in the pricing of the first 160,000 pounds per hour of steam at a nominal annual cost. This change has resulted in lower revenues from steam sales in 1995 as compared to 1994. Additionally, steam revenues for the year ended December 31, 1995 include a fourth quarter annual true-up of $0.4 million.
	Gas resale revenues for the year ended December 31, 1995 were approximately $16.1 million on sales of approximately 8.0 million MMBtu's as compared to approximately $11.6 million on sales of approximately 5.6 million MMBtu's for the corresponding period in the prior year. The increase in gas resale volumes is attributable to the commencement of the Unit 2 firm fuel contracts on November 1, 1994. The decrease in the average gas resale price for the year ended December 31, 1995 as compared to the corresponding period in the prior year is primarily due to weakened demand and lower pricing in the gas resale market.
	Fuel costs for the year ended December 31, 1995 were approximately $84.7 million on purchases of approximately 30.2 million MMBtu's as compared to approximately $36.7 million on purchases of approximately 13.7 million MMBtu's for the corresponding period in the prior year. The increase in the cost of fuel was primarily due to the commencement of Unit 2 commercial operations. In addition, since Unit 2 firm fuel contracts commenced on November 1, 1994, fuel required for the operation of Unit 2 for the months of September and October were purchased on the spot market. These spot market purchases resulted in lower fuel costs than would have been incurred under the firm fuel contracts.
	Operating and maintenance expenses for the year ended December 31, 1995 were approximately $17.2 million as compared to approximately $9.5 million for the corresponding period in the prior year. The increase in operating and maintenance expenses was primarily due to the commencement of Unit 2 commercial operations. As a result of the commencement of Unit 2 commercial operations certain Unit 2 related contracts and certain provisions in existing project contracts commenced. Specifically, the Unit 2 interconnection agreement, the transmission service agreement and the provisions under the water supply agreement commenced September 1, 1994. In addition, upon commencement of commercial operations of Unit 2, Unit 2's share of real estate payments under an agreement for payment in lieu of taxes (the "PILOT Agreement") and future planned overhaul costs, which are accounted for on a straight line basis, are included in operating expenses. Prior to the commencement of Unit 2 commercial operations, these costs we re capitalized.
	Total other operating expenses, excluding amortization of deferred financing charges, for the year ended December 31, 1995 were approximately $6.0 million as compared to approximately $4.2 million for the corresponding period in the prior year. The increase in other operating expenses was primarily due to commencement of Unit 2 commercial operations. Administration expenses increased approximately $0.2 million due to an overall increase in personnel at the plant site as well as start-up support personnel under the Administrative Services Agreement. General expenses increased approximately $1.6 million due to increased insurance premiums, legal fees and other professional services fees. 									
	Amortization of deferred financing charges for the year ended December 31, 1995 was $1.1 million as compared to $0.8 million for the corresponding period in the prior year. The year ended December 31, 1995 includes twelve months of amortization whereas the year ended December 31, 1994 includes only eight months of amortization in connection with the refinancing of the Partnership's debt in May 1994.
	In connection with the refinancing of the Partnership's debt in May 1994, the previous deferred financing charges and the costs associated with breaking the then outstanding interest rate swaps, totaling $34.9 million in the aggregate, were written off. This was a one-time charge to the Partnership's earnings.
	Net interest expense for the year ended December 31, 1995 was approximately $32.4 million as compared to approximately $17.1 million for the corresponding period in the prior year. The increase in net interest expense is attributable to the Partnership refinancing in May 1994 its then existing debt with $392 million in secured long-term bonds at market interest rates. Additionally, until Unit 2 commenced commercial operations, approximately 74% of the Partnership's interest expense for the year ended December 31, 1994 was capitalized.
Liquidity and Capital Resources
	Net cash provided by operating activities for the year ended December 31, 1996 was $32.6 million as compared to net cash provided by operating activities of $12.2 million for the corresponding period in the prior year. This increase in net cash from operating activities is due to the increase in net income and normally recurring cash receipts and disbursements within the Partnership's operating asset and liability accounts for the year ended December 31, 1996 as compared to the corresponding period in the prior year.
	Net cash provided by investing activities for the year ended December 31, 1996 was $3.6 million as compared to net cash provided by investing activities of $13.3 million for the corresponding period in the prior year. Net cash provided by investing activities for the year ended December 31, 1996 primarily represents the net activity in the restricted cash accounts. Net cash provided by investing activities for the year end December 31, 1995 primarily represents the net activity in the restricted cash accounts offset by construction-related activities.
	Net cash used in financing activities for the year ended December 31, 1996 was $36.2 million as compared to net cash used in financing activities of $26.5 million for the corresponding period in the prior year. During the year ended December 31, 1996 approximately $35.5 million was released for distribution to the partners as compared to approximately $21.0 million for the corresponding period in the prior year. The year ended December 31, 1995 reflects a one-time payment to General Electric pursuant to the Steam Sales Agreement.
	The debt service coverage ratio for 1996 calculated pursuant to the Indenture was 1.92:1.
Credit Agreement
	The Partnership has available for its use a $30 million Credit Agreement ("Credit Agreement"), which is to be used by the Partnership for required letters of credit related to various project contracts and for working capital purposes. The maximum amount available under the Credit Agreement for working capital purposes is $10.0 million. At December 31, 1996, no draws had been made against the outstanding letters of credit and no working capital loans were outstanding under the Credit Agreement. Although the Credit Agreement was originally due to expire on August 11, 1997 the Partnership extended the Credit Agreement for an additional three years.
Funds
	In connection with the sale of the Bonds, the Partnership entered into the Depositary 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 depositary agent. 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 two sub-funds of the Partnership Distribution 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 the amounts (each, a "Fund Requirement") established pursuant to the D&D Agreement.
	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 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, 1996 the balance in this Fund was approximately $1.4 million, which exceeded the current Fund Requirement.
	The Interest and Principal Funds relate primarily to the current debt service on the outstanding Bonds. The applicable Fund Requirement is the amount due and payable on the next semi-annual payment date. On December 26, 1996, the monies available in the Interest Fund were used to make the semi-annual interest payment. Therefore, the balance in the Interest Fund at December 31, 1996 was $0. The June 26, 1997 Interest and Principal Fund Requirements will be approximately $17.3 million and approximately $1.1 million, respectively.
	The Fund Requirement for the Debt Service Reserve Fund is an amount equal to the maximum amount of debt service due in respect of all the Bonds outstanding for any six-month period during the succeeding three-year period. At December 31, 1996 the balance in this Fund was approximately $19.1 million. The June 26, 1997 Fund Requirement will be approximately $19.8 million.
	The Partnership Distribution Fund is at the end of the Fund hierarchy and cash distributions to the Partners from these sub-funds can only be made upon the achievement of specific criteria established pursuant to the financing documents, including the D&D Agreement. This Fund does not have a Fund Requirement.
Refinancing
	At March 31, 1994, the Partnership had an existing credit facility which included a term loan with an outstanding balance of $96.3 million and a construction loan with an outstanding balance of $232.4 million. On May 9, 1994 (the "Closing Date") all amounts outstanding under the then existing credit facility were refinanced with the Old Bonds. The Partnership determined that a refinancing of the existing credit facility would benefit the long term operating results of the Partnership, despite the cost to terminate the interest rate swap agreements related to the then existing debt. This decision was a result of management's review of then prevailing market interest rates and the term of the then prevailing credit facility.
	On the Closing Date, the proceeds from the sale of the $392 million in Old Bonds together with approximately $53.8 million available under an equity bridge loan facility were used to refinance all amounts outstanding under the then existing credit facility, to pay approximately $17.4 million in interest rate swap breakage costs associated with the termination of the Partnership's interest rate hedging agreements pertaining to the then existing debt and approximately $17.4 million in transaction costs related to the offering of the Old Bonds and to establish certain reserve Funds under the D&D Agreement. The Partnership also received approximately $5.1 million in capital contributions from certain Partners on the Closing Date and approximately $53.8 million in additional capital contributions from certain Partners following commercial operations of Unit 2, which was used in part to repay the Partnership's obligations under the equity bridge loan facility.
	In November 1994, the Funding Corporation and Partnership offered to exchange like amounts of the New Bonds for Old Bonds. On December 12, 1994, the exchange of all the Old Bonds for the New Bonds was completed.
Year Ended December 31, 1997
	During 1997, the Partnership anticipates its power purchasers will dispatch their respective units in a manner consistent with the dispatch levels in the prior year. In order to achieve dispatch levels similar to those of the prior year or exceed them, the Partnership may enter into special dispatch arrangements which will ultimately enhance the results of operations, including revenues and cash flows, of the Partnership. However, if and when the restructured Niagara Mohawk Power Purchase Agreement goes into effect, the Partnership anticipates that Niagara Mohawk will relinquish its right to direct the dispatch of Unit 1 and that the Partnership would make decisions regarding the operation of Unit 1 based on market conditions then in effect, in light of its anticipated receipt of certain fixed payments under the restructured Niagara Mohawk Power Purchase Agreement.
	As of March 1997, natural gas resale prices for 1997 have been below the prior year's high prices and the Partnership expects, on the average, such prices to remain below 1996 levels for the balance of 1997.
	Future operating results and cash flows from operations are also dependent on, among other things, the performance of equipment and processes as expected, level of dispatch, fuel deliveries and prices as contracted and the receipt of certain capacity and other fixed payments. A significant change in any of these factors could have a material adverse effect on the results for the Partnership.
	The Partnership believes that based on current conditions and circumstances it will have sufficient liquidity available provided by cash flows from operations to fund existing debt obligations and operating costs.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - ----------------------------------------------------
	The financial statements and supplementary data required by this item are presented under Item 14 and are incorporated herein by reference.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND - ----------------------------------------------------------------------------- FINANCIAL DISCLOSURE - -------------------- 	None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE FUNDING CORPORATION AND THE - ----------------------------------------------------------------------------- MANAGING GENERAL PARTNER - ------------------------
	The Managing General Partner is authorized to manage the day to day business and affairs of the Partnership and to take actions which bind the Partnership, subject to certain limitations set forth in the Partnership Agreement. The Managing General Partner has a Board of Directors consisting of two persons elected by its sole stockholder, JMC Selkirk Holdings, Inc. ("Holdings"), a direct subsidiary	 of J. Makowski Company. Pursuant to a board representation agreement with GPUI, Holdings may elect at least four members, and GPUI has the right, at its option, to designate a fifth member of the Board of Directors of the Managing General Partner.
	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: ----------------------------------
		Name		 Age		 Position 		----				 ---					 -------- Joseph P. Kearney............50 	 Chief Executive Officer, President and 		 						 Director P. Chrisman Iribe............45 Executive Vice President and Director John R. Cooper...............49 	 Senior Vice President and Chief 								 Financial Officer David N. Bassett.............50	 Treasurer
Managing General Partner: -------------------------
		Name		 Age		 Position 		----				 ---					 -------- Joseph P. Kearney............50 	 Chief Executive Officer, President and 									 Director P. Chrisman Iribe............45 Executive Vice President and Director John R. Cooper...............49 Senior Vice President and Chief 					 				Financial Officer David N. Bassett.............50	 Treasurer
	Joseph P. Kearney has been President and Chief Executive Officer of U.S. Generating Company ("U.S. Generating"), an affiliate of the Partnership, since it was formed in 1989. Prior to joining U.S. Generating, Mr. Kearney held senior management positions at the Coastal Corporation from 1984 to 1989. Prior to 1984, Mr. Kearney held positions in project and technology development and financing with the Fluor Corporation, Enpex Corporation and System Development Corporation. From 1974 to 1979, Mr. Kearney served as Chief of Energy Technology, White House Office of Management & Budget. He had Executive Office responsibility for financial, policy, legislative, management and budgetary proposals by the U.S. Department of Energy and the Nuclear Regulatory Commission.
	 	P. Chrisman Iribe is Executive Vice President of U.S. Generating, an affiliate of the Partnership, and has been with U.S. Generating since it was formed in 1989. Prior to joining U.S. Generating, 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.
	John R. Cooper is Senior Vice President of U.S. Generating, an affiliate of the Partnership, and has been with U.S. Generating, since it was formed in 1989. Prior to joining U.S. Generating, he spent 3 years as a Chief Financial Officer with a European oil, shipping and banking group. Prior to 1986, Mr. Cooper spent 7 years with Bechtel Financing Services, Inc., where his last position was Vice President and Manager.
	David N. Bassett is Controller and Treasurer of U.S. Generating, an affiliate of the Partnership, and has been with U.S. Generating since it was formed in 1989. Mr. Bassett oversees all accounting and auditing activities, treasury functions and insurance for the projects in which U.S. Generating or certain of its affiliates play a role. Prior to joining U.S. Generating, he worked for Bechtel Enterprises, Inc. and Bechtel Group for over 15 years.
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. GPUI is entitled to name a designee to participate on a non-voting basis in meetings of the Management Committee.
ITEM 11.
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, 1996 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 Facility 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.
ITEM 12.
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:
							 Nature 		 Name and Address		 of Beneficial	 Percentage Title of Class	of Beneficial Owner		 Ownership (1)	 Interest (2)	 - -------------- ------------------- -------------	 ------------
Partnership	 JMC Selkirk, Inc. (3)		 Managing General (i) 2.0417% Interest	 One Bowdoin Square			 Partner		 (ii) 22.4000% 			 Boston, Massachusetts 02114 Limited Partner (iii) 18.1440%
Partnership	 Pentagen Investors, L.P.*(3)(4) Limited Partner (i) 5.2502% Interest	 One Bowdoin Square			 				 	(ii) 57.6000% 			 Boston, Massachusetts 02114			 (iii) 46.6560%
Partnership	 Cogen Technologies 		 General Partner	(i) 1.0000% Interest	 Selkirk GP, Inc.				 (iii) .2211% 			 1600 Smith Street 			 Houston, Texas 77002 (5)
Partnership	 Cogen Technologies 		 Limited Partner (i) 78.1557% Interest	 Selkirk LP..					 (iii) 17.2789% 		 1600 Smith Street 			 Houston, Texas 77002 (5)
Partnership EI Selkirk, Inc. (6)		 Limited Partner (i) 13.5523% Interest One Upper Pond Road			 	 (ii) 20.0000% 			 Parsippany, New Jersey 07054			 (iii) 17.7000%
* Formerly known as JMCS I Investors, L.P.
(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.
(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 EI 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)	J. Makowski Company is the indirect beneficial owner of JMC Selkirk and a 	50% indirect beneficial owner of Investors (formerly known as JMCS I 	Investors, L.P.). All of the capital stock of J. Makowski Company is 	held by Beale Generating Company, a special purpose corporation jointly 	owned by subsidiaries of PG&E Enterprises and Bechtel Enterprises, Inc.
(4)	50% of the interests in Investors are beneficially owned by Tomen 	Corporation, a Japanese trading company.
(5)	Cogen Technologies GP is beneficially owned by Robert C. McNair (88.3%) 	and members of his family (11.7%). Cogen Technologies LP is beneficially 	owned by Robert C. McNair (72.155%), members of his family (9.561%) and 	certain of his associates (18.284%). Mr. McNair has voting control of 	each of Cogen Technologies GP and Cogen Technologies LP.
(6)	GPUI, Inc. is the indirect beneficial owner of EI 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. Cogen Technologies GP and Cogen Technologies, L.P. are also affiliated.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - --------------------------------------------------------
	JMCS I Management, a wholly-owned indirect subsidiary of J. Makowski Company, provides management and administrative services for the Facility under the Administrative Services Agreement. All of the directors and officers 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 7 to the Consolidated Financial Statements, appearing elsewhere in this report, for a discussion of the Partnership's related party transactions.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K - ------------------------------------------------------------------------
(a)	1. Financial Statements
	 The following financial statements are filed as part of this Report:
	 Report of Independent Auditors................................... 	 	 Report of Independent Auditors...................................
	 Balance Sheets as of December 31, 1996 and December 31, 1995.....
	 Statements of Operations for the years ended December 31, 1996 	 and December 31, 1995 and the nine months ended December 31, 1994.
Statements of Partners' Capital for the years ended December 31, 1996 and December 31, 1995 and the nine months ended December 31,1994..................................................
	 Statements of Cash Flows for the years ended December 31, 1996 	 and December 31, 1995 and the nine months ended December 31, 1994.
Notes to Consolidated Financial Statements........................
	2. Financial Statement Schedule
	 The following financial statement schedule is filed as part of this 	 Report:
	 Schedule II	Valuation and Qualifying Accounts.................... S-1
All other schedules have been omitted because the information is not applicable.
	3.	Exhibits
	The exhibits listed on the accompanying Index to Exhibits are filed as part of this Report.
(b)		Reports on Form 8-K
		On March 14, 1997, the Registrant filed a report on Form 8-K disclosing the global agreement reached between Niagara Mohawk and 19 Independent Power Producers.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
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 as of December 31, 1996 and 1995, and the related consolidated statements of operations, partners capital and cash flows for the years then ended. These 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 did not audit the accompanying consolidated statements of operations, partners capital and cash flows for the nine months ended December 31, 1994. Those financial statements were audited by other auditors whose report dated March 28, 1995 expressed an unqualified opinion on those statements.
We conducted our audits in accordance with generally accepted auditing standards. 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, based on our audits, the financial statements referred to above present fairly, in all material respects, the financial position of Selkirk Cogen Partners, L.P. and its subsidiary as of December 31, 1996 and 1995, and the results of their operations and their cash flows for the years then ended, in conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the consolidated financial statements taken as a whole. The schedule listed in the accompanying index is the responsibility of the Partnership's management and is presented for purposes of complying with the Securities and Exchange Commissions rules and is not part of the basic consolidated financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the consolidated financial statements and, in our opinion, based on our audit, fairly states, in all material respects, the financial data required to be set forth therein in relation to the consolidated financial statements taken as a whole.
												ARTHUR ANDERSEN, LLP
Washington, D.C. March 14, 1997
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners of Selkirk Cogen Partners, L.P. (A Delaware limited partnership)
	We have audited the accompanying balance sheets of Selkirk Cogen Partners, L.P. as of December 31, 1994 and March 31, 1994 and the related statements of operations, partners capital and cash flows for the nine months ended December 31, 1994 and for the years ended March 31, 1994 and 1993. Our audits also included the financial statement schedule listed in the Index at Item 14(a). These financial statements and schedule are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
	We conducted our audits in accordance with generally accepted auditing standards. 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, based the financial statements referred to above present fairly, in all material respects the financial position of Selkirk Cogen Partners, L.P. at December 31, 1994 and March 31, 1994, and the results of its operations and cash flows for the nine months ended December 31, 1994 and for the years ended March 31, 1994 and 1993, in conformity with generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
													ERNST & YOUNG LLP
Boston, Massachusetts March 28, 1995
				 																							
											 											 																				
											 											 																				
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996 AND 1995
1.	Organization and business 	-------------------------
	Selkirk Cogen Partners, L.P. (Selkirk or the Partnership) was organized 	on December 15, 1989 as a Delaware limited partnership. Prior to the 	Partnership agreement, the partners had a cost sharing arrangement for 	costs incurred from the project's inception in October 1987. See Note 3 	for a discussion of the general and limited partners and their respective 	equity interests.
	Selkirk Cogen Funding Corporation (Funding Corporation) was organized as 	a wholly-owned subsidiary of the Partnership for the sole purpose of 	facilitating financing activities of the Partnership (see Note 4).
	Selkirk was formed for the purpose of constructing, owning and operating 	a natural gas-fired combined-cycle cogeneration facility located on 	General Electric Company's (GE) property in Bethlehem, New York (the 	Facility). 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 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. Selkirk received construction financing for Unit 1 in June 	1990 and commercial operations commenced on April 17, 1992. Unit 2 	obtained construction financing in October 1992 and commercial operations 	commenced September 1, 1994. Both Units are fueled by Canadian natural 	gas purchased under firm 15-year natural gas supply contracts (extendible 	to 20 years upon satisfaction of certain conditions). Unit 1 is selling 	at least 79.9 MW of electric capacity and associated energy to Niagara 	Mohawk Power Corporation (NIMO) under a 20-year contract and Unit 2 is 	selling 265 MW of electric capacity and associated energy to Consolidated 	Edison Company of New York (ConEd) under a 20-year contract. Also, the 	Partnership makes excess gas lay-off sales during periods when Units 1 	and 2 are not operating at full capacity (see Note 6). Historical 	natural gas resale prices have resulted in significant gas resale margins 	for the Partnership during the years ended December 31, 1996 and 1995. 	Historical natural gas prices may not be indicative of future natural gas 	market prices.
	Unit 1 of the Facility is currently certified as a qualifying facility 	(QF) under the Public Utility Regulatory Policy Act of 1978, as amended 	(PURPA). Accordingly, the prices charged for the sale of electricity and 	steam are not regulated. When Unit 2 commenced operations the Facility 	was no longer qualified by the State of New York but continues to be 	certified by the FERC as a QF. However, this is not expected to have a 	material impact on Selkirk's financial position or operations. Certain 	fuel transportation agreements entered into by Selkirk are subject to 	regulation on the federal and provincial levels in Canada. Selkirk has 	obtained all material Canadian governmental permits and authorizations 	required for operation.
									
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Summary of significant accounting policies 	------------------------------------------
	Basis of presentation 	---------------------
	The preparation of financial statements in conformity with generally 	accepted accounting principles requires management to make estimates and 	assumptions that affect the reported amounts of assets and liabilities 	and disclosure of contingent assets and liabilities at the date of the 	financial statements and the reported amounts of revenues and expenses 	during the reporting period. Actual results could differ from those 	estimates.
	The statements of operations reflect the results of operations of Unit 1 	and for Unit 2 beginning September 1, 1994, the date Unit 2 operations 	commenced. Amounts incurred or accrued for Unit 2 from inception until 	Unit 2's commercial operation date were capitalized or deferred.
	The statements of operations for the years ended December 31, 1996 and 	and 1995 and the nine months ended December 31, 1994 include the 	activities of the Funding Corporation. All intercompany balances and 	transactions have been eliminated
	Effective December 31, 1994, the Partnership changed its fiscal year end 	from March 31 to December 31.
	Cash and cash equivalents 	-------------------------
	The Partnership considers all non restricted liquid securities with an 	original maturity of three months or less to be cash equivalents.
	Restricted funds and long-term restricted funds 	-----------------------------------------------
	All cash and cash equivalents are restricted as to their use under the 	deposit and disbursement agreement. Certain of the Restricted funds are 	associated with transactions or events which are applicable to periods 	beyond the current accounting period and are, therefore, classified as 	long-term. All other Funds are classified as current assets.
									
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	Allowance for doubtful accounts 	-------------------------------
	An allowance for doubtful accounts is established when it appears 	collectability of all or a portion of a customer account receivable is 	unlikely. The allowance for doubtful accounts at December 31, 1996 and 	1995 was $0 and $87,000, respectively.
	Construction work-in-progress 	-----------------------------
	For the nine months ended December 31, 1994, Unit 2 capitalized interest, 	net of interest earned, of approximately $9,327,000. Upon commencement 	of commercial operations of Unit 2, construction costs were reclassified 	to plant and equipment and depreciation commenced accordingly.
	Deferred financing charges 	--------------------------
	Deferred financing charges relate to costs incurred to issue long-term 	obligations and are amortized using the effective interest rate method 	over the lives of the loans to which they pertain.
	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 as follows:
				 Cogeneration facility		 	30 years					 				 Computer systems				 7 years	 				 Office equipment				 5 years
	A maintenance and repairs reserve is recorded based upon scheduled major 	maintenance plans for 20 years. Other maintenance and repairs are 	charged to expense as incurred.
	Fuel inventory and supplies 	--------------------------- 					 	Inventories are stated at the lower of cost or market. Costs for 	materials, supplies and oil inventories were determined by the first-in, 	first-out method. Beginning November 1994, costs are determined on an 	average cost method. The impact of the change in accounting method was 	immaterial.
									
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	Real estate taxes 	-----------------
	Real estate tax payments made under the Partnership's payment in lieu of 	taxes (PILOT) agreement are recognized on a straight-line basis over the 	term of the agreement.
	Accrued expenses 	----------------
	Accrued expenses consist of the following (in thousands):
							 	 December 31, 	 December 31, 						 		 1996 	 1995 	 									------------- ------------
		Accrued fuel costs			 $12,250			 	 $ 7,888 		Accrued wheeling			 466		 466 		Accrued PILOT 				 1,050		 		 950 		Accrued NY gas import taxes 114		 		 1,371 		Accrued utilities			 982		 		 781 		Accrued plant purchases		 518		 		 499 		Accrued bond interest		 385		 		 385 		Other accrued expenses		 859		 		 908 							 -------				 ------- 							 $16,624				 $13,248 									 ------- ------- 									 ------- -------
	Interest rate and currency swap agreements 	------------------------------------------
	In connection with its asset and liability management policies, Selkirk 	entered into various types of hedging agreements. The periodic net 	interest settlement on interest rate swap agreements was recognized as a 	yield adjustment recorded to interest income or expense as appropriate. 	Gains and losses on currency exchange contracts are included in net 	income in the period in which the exchange rate changed. Market risk was 	mitigated through these swap transactions. The interest rate swap 	agreements were terminated in 1994.
	Revenue recognition 	--------------------
	Revenues for the sale of electricity and steam are recorded based on 	monthly output delivered as specified under contractual terms. Revenues 	for the sale of excess gas are recorded in the month sold.
									
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	Income taxes 	------------
	Income taxes have not been provided for in the accompanying financial 	statements because taxes, if any, are the responsibility of the partners.
	New accounting pronouncement 	---------------------------- 	In March 1995, the Financial Accounting Standards Board issued Statement 	of Financial Accounting Standards (SFAS) No. 121, Accounting for the 	Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed Of, 	effective for fiscal years beginning after December 15, 1995. SFAS No. 	121 establishes accounting standards for the impairment of long-lived 	assets and requires that a loss be recognized for those assets if the sum 	of the expected future cash flows from the use of the asset and its 	eventual disposition (undiscounted) is less than the carrying amount of 	the asset. The Partnership adopted SFAS No. 121 on January 1, 1996. The 	adoption of this accounting principle has had no material impact on the 	Partnership.
3. Partners' capital 	-----------------
	In June 1995, the partnership agreement was amended to reflect conversion 	of the general partnership interest in the Partnership held by JMCS I 	Investors, L.P. (now known as Pentagen Investors, L.P. (Investors)) to a 	limited partnership interest and the assignment of a portion of Investors 	limited partnership interest in the Partnership to JMC Selkirk, Inc.
	The general and limited partners, along with their respective equity 	interests are as follows:
	December 31, 1996 and 1995: 	--------------------------- 	 							 							 Interest 	General partners		Affiliate of		 Preferred Original 	---------------- ------------ --------- ---------
	JMC Selkirk, Inc.	 J. Makowski Company, Inc.(JMC) .09%	 1.00% 	Cogen Technologies		 	 Selkirk GP, Inc. Cogen Technologies, Inc.	 1.00%	 ---%
									 										 									
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
								 								 Interest 	Limited partners			Affiliate of			 Preferred	Original	 	---------------- ----------- --------- -------- 	JMC Selkirk, Inc. 		 J. Makowski Company, Inc. 1.95% 21.40% 	Pentagen Investors, L.P. J. Makowski Company, Inc. 5.25% 	 57.60% 	EI Selkirk, Inc.		 GPU International, Inc.	 13.55%	 20.00% 	Cogen Technologies 	 Selkirk, L.P.			 Cogen Technologies, Inc. 78.16%	 ---%
Under the terms of the amended partnership agreement, cash available is 	first distributed 99% to the partners in accordance with their respective 	equity interests (preferred equity) and 1% is allocated based on the 	original ownership structure between JMC affiliates and GPU 	International, Inc. (GPUI). Any additional funds available after the 	preferred distribution, are distributed 99% to the initial equity holders 	and 1% to the preferred equity holders. Subsequent to the eighteenth 	anniversary of Unit 2's commercial operations or the date on which all 	the preferred partners achieve a specified return, distributions will be 	made in accordance with the residual interest; JMC affiliates at 64.8%, 	GPUI at 17.7% and Cogen Technologies, Inc. at 17.5%.
4. Debt financing --------------
	On May 9, 1994, the Funding Corporation, a wholly-owned subsidiary of the 	Partnership, issued an aggregate of $392,000,000 in bonds of which a 	portion was used to refinance the outstanding indebtedness of the 	Partnership. The bonds consist of $165,000,000 which matures on December 	26, 2007 at an interest rate of 8.65% with principal and interest payable 	semi-annually on June 26 and December 26 of each year with principal 	payments commencing June 26, 1996 and $227,000,000 which matures on June 	26, 2012 at an interest rate of 8.98% with principal and interest payable 	semi-annually on June 26 and December 26 of each year with principal 	payments commencing December 26, 2007.
	The scheduled principal payments on the bonds are as follows:
				1997	 $ 2,167,167 				1998				 3,297,597 				1999		 		 4,822,151 				2000		 		 7,306,785 				2001		 11,062,070 									 									
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	The loans are secured by liens on, and security interests in, 	substantially all of the assets of the Partnership. These loans are 	non-recourse to the individual partners. The trust indenture restricts 	the ability of Selkirk to make distributions to the partners under 	certain circumstances.
	In connection with the bond financing, Selkirk was required to register 	the bonds with the Securities and Exchange Commission (SEC) by November 	6, 1994. The filing was completed and declared effective on November 2, 	1994 by the SEC.
	In 1994, Selkirk entered into a combined working capital and bank 	reimbursement agreement (Credit Agreement). The Credit Agreement has a 	maximum available amount of $30,000,000 to be used by Selkirk for 	required letters of credit related to various project contracts and 	working capital purposes. The maximum amount available under the Credit 	Agreement for working capital purposes is $10,000,000. No amounts have 	been drawn under the Credit Agreement.
	Interest and currency swap agreements 	-------------------------------------
	At March 31, 1994, Selkirk had four interest rate swap agreements with 	notional amounts of $112,330,500, $14,771,250, $55,000,000 and 	$25,000,000. In accordance with the terms of these agreements, Selkirk 	paid interest at a fixed rate and received interest at a variable rate, 	determined monthly or quarterly. The effect of fluctuations in the 	interest to be received by Selkirk was intended to offset the effect of 	fluctuations in the variable interest being paid on the construction and 	term loans.
	In conjunction with the issuance of the bonds and related refinancing, 	the Partnership terminated the interest rate swap agreements and paid 	approximately $17,991,000 in breakage fees (including accrued interest of 	approximately $550,000), of which $2,087,000 related to rate lock 	breakage costs. These fees were paid from the net proceeds of the bond 	financing.
	On June 20, 1990 and October 29, 1992, Selkirk entered into currency 	exchange agreements to hedge against future exchange rate fluctuations 	which could result in additional costs incurred under fuel transportation 	agreements which are denominated in Canadian dollars. The June 1990 	agreement relates to Unit 1 under which Selkirk exchanges approximately 	$368,000 U.S. dollars for $458,000 Canadian dollars on a monthly basis 	commencing on December 25, 1992 and terminating December 25, 2002. The 	October 1992 agreement relates to Unit 2 under which Selkirk exchanges 	approximately $1,044,000 U.S. dollars for $1,300,000 Canadian dollars on 	a monthly basis commencing on May 25, 1995 and terminating December 25, 	2004. 									 									
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	Selkirk is exposed to credit loss under the currency agreements. In the 	unlikely event that a counterparty fails to meet the terms of the 	agreements, Selkirk's exposure is limited to the currency exchange rate 	differential. However, Selkirk does not anticipate nonperformance by the 	counterparties.
5. Disclosure of fair market value of financial instruments 	--------------------------------------------------------
	The following methods and assumptions were used by the Partnership in 	estimating its fair value disclosures for financial instruments as of 	December 31, 1996 and 1995:
	Cash: The carrying amount reported in the balance sheet for cash 	approximates its fair value of $2,591,000 and $2,672,000 at December 31, 	1996 and 1995, respectively.
	Restricted funds: The carrying amount reported in the balance sheet for 	restricted funds approximates its fair value of $26,730,000 and 	$30,916,000 at December 31, 1996 and 1995, respectively.
	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 at December 31, 1996 and 1995 is approximately $383,183,000 and 	$391,964,000, respectively.
	Currency swap agreements: The fair value of the currency exchange 	arrangements represents the termination value of approximately $6,588,000 	and $4,933,000 at December 31, 1996 and 1995, respectively, estimated 	using current exchange rates.
6. Commitments 	----------- 	Selkirk has entered into site lease, property tax, fuel supply and 	transportation, power sales, steam sales, electric interconnection and 	transmission, operations and maintenance, water supply and project 	administrative agency agreements. In connection with the construction 	and operation of the Facility, Selkirk is obligated under the following 	agreements:
									
										
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	Power sales agreements - electricity 	------------------------------------
	In December 1987, Selkirk entered into a power sales agreement, as 	amended, with NIMO, for the sale of electricity, for an initial term of 	20 years commencing on the date of commercial operations, April 17, 1992. 	The agreement may be terminated upon two years written notice to NIMO and 	payment of a termination fee or upon the loss of Selkirk's status as a 	QF. 	 	In April 1994, the power sales agreement with NIMO was amended and, 	pursuant to this amended agreement, the Partnership paid NIMO $1,250,000 	as a consent fee from the proceeds of the bond offering. In addition, 	the Partnership posted a letter of credit for approximately $15,000,000 	under the Credit Agreement.
	On October 6, 1995, NIMO filed its "PowerChoice" proposal with the New 	York State Public Service Commission ("NYPSC"). On October 12, 1995, 	NIMO filed a Report on Form 8-K with the SEC explaining the PowerChoice 	proposal (the "PowerChoice Statement"). In the PowerChoice Statement, 	NIMO describes a number of related proposals to restructure the utility's 	business, including the reorganization of its assets and the 	renegotiation of its contracts with generators which, like the 	Partnership, are not regulated as utilities ("non-utility generators"). 	In connection with PowerChoice, NIMO filed a Report on Form 8-K on March 	10, 1997 with the SEC in which it announced an agreement in principle to 	restructure or terminate 44 power purchase contracts. Among the 	contracts which is proposed to be restructured is the NIMO power sales 	agreement for the electric output of Unit 1. Pursuant to the agreement 	in principle and subject to negotiation as described below, the parties 	propose to restructure the NIMO power sales agreement to provide for 	payments from NIMO which may be under one or more pricing arrangements 	for up to 12 years in lieu of the rates which would be payable under the 	current NIMO power sales agreement.
	The details of the price arrangements as well as other possible contract 	modifications are yet to be negotiated, and implementation of the 	agreement in principle is subject to a number of significant conditions, 	including execution of binding agreements; any requisite corporate, 	partnership and shareholder approvals; NYPSC approval of the agreement in 	principle and other related transactions; other state and federal 	approvals; the resolution of all tax issues; and obtaining required 	amendments or waivers under existing credit agreements and third-party 	contracts, including, with respect to the Partnership, satisfying certain 	standards under the trust indenture relating to the absence of material 	adverse changes and the maintenance of required projected debt service 	coverage ratios or receiving any required approval of holders of the 	bonds or other creditors. 	 	The Partnership, as a party to the agreement in principle, is committed 	to negotiate to reach agreement on a restructured power sales agreement; 	however, the Partnership expresses no opinion with respect to the 	likelihood that all of the conditions to implementation of the agreement 	in principle
					 			
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	will be met or that all of the other elements of PowerChoice will be 	realized. Further, the Partnership expresses no opinion with respect to 	the viability of NIMO's proposed alternatives should PowerChoice fail, 	such as NIMO's proposal to take possession of independent power projects 	through the power of eminent domain and to thereafter sell such projects 	or NIMO's position that it has not ruled out the ultimate possibility of 	a filing for restructuring under Chapter 11 of the U.S. Bankruptcy Code 	as set forth in the PowerChoice Statement. Nevertheless, in the absence 	of agreement on a definitive restructured power sales agreement, the 	Partnership continues to believe that the NIMO power sales contract is a 	valid a nd binding contract with NIMO. Until negotiations on the 	restructured power sales agreement advance further, the Partnership will 	not be able to determine what effect, if any, the restructured power 	sales agreement or the PowerChoice proposal will have on the Partnership, 	its business or net operating revenues. For the year ended December 31, 	1996, electric sales to NIMO accounted for approximately 17.1% of total 	project revenues.
	As a result of the announcement of the agreement in principle, Standard & 	Poor's has placed the bonds on credit watch "with negative implications," 	based in part on its analysis of Form 8-K recently filed by NIMO and the 	Partnership, respectively and its belief that the restructuring has the 	potential to erode cash flow coverage derived from long-term contracts 	supporting the bonds. As of the date of this report, Moody's Investors 	Service has not changed its rating or its "negative outlook" on the 	bonds.
	Selkirk has also entered into a power sales agreement with ConEd, for the 	sale of electricity, for an initial term of 20 years commencing on 	September 1, 1994, the date of Unit 2 commercial operations. The 	contract is extendible under certain circumstances.
	On February 6, 1995, Selkirk provided ConEd with a letter of credit in 	the amount of approximately $1,046,000. The letter of credit represented 	security pursuant to Article 13 of the ConEd power sales agreement and 	expired February 6, 1996.
	The power sales agreements with NIMO and ConEd each provide the 	purchasing utility with the contractual right to schedule the related 	Unit for dispatch on a daily basis at full capability, partial capability 	or off-line. Each purchasing utility's scheduling decisions are required 	to be based in part on economic criteria which, pursuant to the governing 	rules of the New York Power Pool, 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 NIMO and ConEd if Selkirk does not maintain a 	minimum availability level.
	ConEd, by a letter dated September 19, 1994, claimed the right to acquire 	that portion of Unit 2's natural gas supply not used in operating Unit 2 	(the "excess gas"), when Unit 2 is dispatched off-line or at less than 	full capability. The ConEd power sales agreement contains no express 	language granting ConEd any rights to such excess gas and the Partnership 	has stated to ConEd that claims to excess gas are without merit. To date 	ConEd has paid all amounts invoiced by the Partnership in accordance with 	the ConEd power purchase agreement.
									
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	If ConEd were to prevail in its claim to Unit 2's excess natural gas 	volumes, the Partnership would lose its ability to engage in lay-off 	sales of such volumes at favorable prices relative to their costs, and 	thus the Partnership's cash flows from gas resale activities would also 	be materially and adversely affected. The Partnership is unable to 	determine the outcome of this uncertainty. 	 	In August 1992, NIMO filed a petition requesting the NYPSC to authorize 	NIMO to curtail purchases from, and avoid payment obligations to, 	non-utility generators, including QF's such as Selkirk, during certain 	periods. NIMO has claimed that such curtailment would be consistent with 	PURPA, and the regulations promulgated thereunder, which contemplate 	utilities' curtailing purchases from QF's in certain circumstances. The 	NYPSC has initiated an investigation but has not issued an order in this 	proceeding, nor has the NYPSC indicated when it intends to do so. There 	can be no certainty that NYPSC will not issue an order in this proceeding 	that authorizes NIMO and ConEd to curtail purchases of electricity from 	dispatchable facilities such as Selkirk, nor is it possible to predict at 	this time how such curtailment rights, if so authorized, would be 	implemented or whether the exercise of such curtailment rights would 	entail a reduction in the capacity payments otherwise payable under the 	power sales agreements.
	On August 30, 1996 the NYPSC reopened the curtailment proceedings and 	directed an administrative law judge to prepare a recommended decision 	under an abbreviated deadline. In light of Niagara Mohawk reaching 	agreement in principle to restructure or terminate 44 power purchase 	contracts (see Part I Item 1. Business- The Facility and Certain Project 	Contracts- Niagara Mohawk for discussion of the agreement in principle), 	the NYPSC did not present a ruling in the case. The Partnership expects 	that any agreement which it enters into with Niagara Mohawk to implement 	the agreement in principle will waive Niagara Mohawk's right, if any, to 	curtail purchases from the Partnership.
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	Steam sales agreements 	----------------------
	In February 1990, Selkirk entered into a steam sales agreement for Unit 	1, as amended, with GE for an initial term of 20 years, effective from 	the date of commercial operations. On October 21, 1992, Selkirk and GE 	entered into a new steam sales agreement, as amended with a term of 20 	years from the commercial operations date of Unit 2 and may be extended 	under certain circumstances. The Unit 1 steam sales agreement terminated 	upon the commercial operations of Unit 2. 		 	Until Unit 2 achieved commercial operations, GE had agreed to forego 	(subject to later repayment plus interest) the discount on a certain 	quantity of steam supplied by Selkirk during a quarter to the extent 	necessary for Selkirk to maintain a quarterly debt service coverage ratio 	of 1.2 to 1 and the advances, with interest, are repayable to the extent 	Selkirk's quarterly debt service coverage ratio exceeds 1.3 to 1. Under 	this agreement, Selkirk had invoiced and received from GE approximately 	$899,000 and $4,123,000 at December 31 and March 31, 1994, respectively. 	In April 1995, the Partnership paid off the outstanding principal amount 	and approximately 75% of the associated accrued interest. The 	Partnership paid the remaining accrued interest in January 1996 and 	February 1997. 	 	GE is obligated under the steam sales agreement to purchase the minimum 	quantities of steam necessary for the Facility to maintain its QF status. 	In the event that GE were to fail to purchase and take this minimum 	quantity, the Partnership could acquire title to the Facility Site, 	terminating the Lease Agreement, at no cost to the Partnership. 	 	The agreement provides GE the right of first refusal to purchase the 	Facility, subject to certain pricing considerations. Additionally, GE 	has the right to purchase the boiler facility that produces the steam at 	a mutually agreed upon price if and when the steam sale agreement is 	terminated. The steam sales agreement may be terminated by Selkirk with 	one year's written notice if either the NIMO or ConEd power sales 	agreement is terminated. It may also be terminated by GE with two years' 	written notice if GE's plant no longer has a requirement for steam.
	Fuel supply and transportation agreements 	-----------------------------------------
	Selkirk has entered into 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 which began in November 1992, 	with an option to extend for an additional 5 years upon satisfaction of 	certain conditions.
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	Selkirk entered into firm natural gas supply agreements with various 	suppliers for Unit 2. The agreements have an initial term of 15 years, 	which began November 1, 1994, and an option to extend for an additional 	5-year term upon satisfaction of certain conditions.
	Each Unit 2 gas supply contract requires that Selkirk purchase a minimum 	of 75% of the maximum annual contract volumes each year. If the 	Partnership fails to take this minimum quantity, then the shortfall 	amount between the minimum required volumes and the actual nominations 	must be made up in the following year(s). The Partnership is allowed up 	to two years under these contracts during which time the Partnership may 	make up any shortfall. If the Partnership does not make up the shortfall 	within these periods, then the suppliers have a right to reduce the 	maximum daily contract quantity by the shortfall. The Partnership 	purchased approximately $35,191,000, $28,736,000 and $5,198,000 in gas 	from these suppliers for the years ended December 31, 1996 and 1995 and 	the nine months ended December 31, 1994, respectively.
	Selkirk has entered three 20-year agreements for firm fuel transportation 	service to supply Unit 1 commencing November 1, 1992. In accordance with 	one of these agreements, Selkirk posted a letter of credit in the amount 	of approximately $586,000 in October 1992. 	 	Selkirk has entered into three agreements for firm fuel transportation 	service for Unit 2. The agreements commenced in November 1994 and have 	terms of 20 years. Upon the execution of the transportation agreement 	with one transporter, the various fuel suppliers posted letters of credit 	totaling approximately $10,007,000 Canadian dollars for the benefit of 	the transporter on behalf of Selkirk which was subsequently reduced to 	approximately $9,814,000 Canadian dollars in February 1997. Selkirk will 	reimburse all costs related to obtaining and maintaining the letters of 	credit. Selkirk also posted two letters of credit related to the 	remaining two firm fuel transportation agreements for approximately 	$796,000 and $2,090,000. 	 	Electric interconnection and transmission agreements 	----------------------------------------------------
	Selkirk constructed an interconnection facility to transfer power from 	Unit 1 to NIMO and transferred title of the facility to NIMO. Selkirk 	has agreed to reimburse NIMO $150,000 annually for the operation and 	maintenance of the facility. The term of the agreement is for 20 years 	from the commercial operations date of Unit 1 and may be extended if the 	power sales agreement with NIMO is extended.
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	 	In December 1990, Selkirk entered into a 20-year firm interruptible 	transmission agreement with NIMO, as amended, to transmit power from Unit 	2 to ConEd, beginning with commercial operations. In connection with 	this agreement, Selkirk constructed an interconnection facility and 	transferred title to NIMO in 1995. Under the terms of this agreement, 	Selkirk will reimburse NIMO $450,000 annually for the maintenance of the 	facility. 	 	Site lease 	----------
	In February 1990, Selkirk entered into an operating lease agreement, 	amended in June 1990, to lease certain property from GE, on which the 	Unit 1 facility is located, at $1 per annum. On October 21, 1992, 	Selkirk entered into a second and amended lease agreement to include the 	additional land for Unit 2. Annual rent is $1,000,000, payable monthly 	in advance, two-thirds of which was capitalized by Unit 2 until the 	commencement of commercial operations. Rent expense was approximately 	$1,000,000, $1,000,000 and $425,000 for the years ended December 31, 1996 	and 1995 and the nine months ended December 31, 1994. The amended lease 	term expires on the twentieth anniversary of the commercial operations 	date of Unit 2 and is renewable for the greater of 5 years or until 	termination of any power sales contract, to a maximum of 20 years. The 	lease may be terminated by Selkirk under certain circumstances with the 	appropriate written notice during the initial term. 	 	 	Payment in lieu of taxes agreement 	----------------------------------
	In October 1992, Selkirk entered into a payment in lieu of taxes (PILOT) 	agreement with the Town of Bethlehem Industrial Development Agency (IDA), 	a corporate governmental agency, which exempts Selkirk from all property 	taxes, except for special assessments. The agreement commenced on 	January 1, 1993, and terminates on December 31, 2012. 	 	On the closing date of the facility lease agreement with the IDA, Selkirk 	paid the IDA $250,000 as one half of a $500,000 financing fee; the second 	installment was paid upon completion of Unit 2 and issuance by the Town 	of Bethlehem of a final certificate of occupancy. PILOT payments are due 	semi-annually in equal installments and are scheduled for the years as 	follows:
				1997		 $ 2,100,000 				1998			 2,300,000 				1999			 2,500,000 				2000			 2,700,000 				2001			 2,900,000 				Thereafter	 42,300,000
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	Other agreements 	----------------
	Selkirk has an operations and maintenance services agreement with GE 	whereby GE will provide certain operation and maintenance services during 	the operations of Unit 1 and the construction of Unit 2 and for seven (7) 	years after the Unit 2 commercial operations date on a cost plus fixed 	fee basis. In addition, Selkirk has entered into a 20-year take or pay 	water supply agreement with the Town of Bethlehem under which Selkirk is 	committed to make minimum annual purchases of approximately $1,000,000, 	subject to adjustment for changes in market rates beginning in the tenth 	year.
7. Related parties 	---------------
	An affiliate of JMC Selkirk, Inc. has been appointed project 	administrative agent to manage the day-to-day affairs of Selkirk. This 	affiliate is compensated at agreed-upon billing rates which are adjusted 	annually in accordance with an administrative services agreement. For 	the years ended December 31, 1996 and 1995 and the nine months ended 	December 31, 1994 approximately $2,715,000, $2,419,000 and $4,057,000, 	respectively was incurred for services rendered of which $1,869,000 is 	reflected in general and administrative expenses and $2,188,000 has been 	capitalized relating to construction of Unit 2 and the bond financing for 	the nine months ended December 31, 1994.
	 	During the years ended December 31, 1996 and 1995 and the nine months 	ended December 31, 1994, Selkirk purchased approximately $0, $564,000 and 	$1,054,000, respectively and sold approximately $0, $428,000 and 	$313,000, respectively, in fuel at its fair market value to JMC Fuel 	Services, Inc., an affiliate of JMC Selkirk, Inc. During the years ended 	December 31, 1996 and 1995 and the nine months ended December 31, 1994, 	Selkirk purchased approximately $16,000, $3,313,000 and $701,000, 	respectively and sold approximately $238,000, $320,000 and $228,000, 	respectively in fuel at its fair market value in transactions with other 	affiliates of JMC Selkirk, Inc. Of the $701,000 purchased approximately 	$164,000 was capitalized in construction working-process as start up 	fuel. Purchases are included in fuel costs and sales are included in gas 	resales in the statements of operations, except as noted above. 	 	During the year ended December 31, 1996, Selkirk entered into an Enabling 	Agreement with US Gen Power Services, L.P.("USGEN PS"), an affiliate of 	JMC Selkirk,Inc., to enter into certain transactions for the purchase and 	sale of energy and other services. During the year ended December 31, 	1996, Selkirk entered into two energy and capacity sale transactions with 	USGEN PS totaling approximately $45,000.
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
	Selkirk has two agreements with Iroquois Gas Transmission System (IGTS) 	to provide firm transportation of natural gas from Canada. An affiliate 	of JMC Selkirk, Inc. has a partnership interest in IGTS.
8.	Contingency -----------
	In connection with transactions in 1994 involving the investment by 	affiliates of Cogen Technology, Inc. in the Partnership and the purchase 	of J. Makowski Company, Inc. by Beale Generating Company, the Partnership 	filed New York State real estate transfer and gains tax returns with New 	York tax authorities. The New York tax authorities have raised certain 	questions and issues about such tax returns. 	 	Although the New York tax authorities have assessed no additional tax 	against the Partnership or any other transferor at this time, the issue 	currently is under consideration and it is possible that the New York tax 	authorities will assert that additional tax is owed by the Partnership or 	one or more of the other transferors in connection with these 	transactions. The Partnership presently cannot predict the likelihood of 	the New York tax authorities making such an assertion or, if made, the 	amount of tax that might be asserted.
									 9.	Subsequent Event 	----------------
	In connection with PowerChoice, NIMO filed a Report on Form 8-K on March 	10, 1997 with the SEC in which it announced an agreement in principle to 	restructure or terminate 44 power purchase contracts. Among the 	contracts which is proposed to be restructured is the NIMO power sales 	agreement for the electric output of Unit 1. Pursuant to the agreement 	in principle and subject to negotiation as described elsewhere in these 	notes to consolidated financial statements, the parties propose to 	restructure the NIMO power sales agreement to provide for payments from 	NIMO which may be under one or more pricing arrangements for up to 12 	years in lieu of the rates which would be payable under the current NIMO 	power sales agreement. 	 	See Note 6. Commitments: Power sales agreements - electricity for 	additional disclosure regarding the agreement in principle to restructure 	the NIMO power sales agreement.
									
Exhibit No.		Description of Exhibit - ----------- ----------------------
3.1(1)			Certificate of Incorporation of Selkirk Cogen Funding 			Corporation (the "Funding Corporation")
3.2(1) 			 By-laws of the Funding Corporation
3.3(1)			Second Amended and Restated Certificate of Limited 	 			Partnership of Selkirk Cogen Partners, L.P. (the 	 			"Partnership")
3.4(1)			Third Amended and Restated Agreement of Limited Partnership 				of the Partnership, dated as of May 1, 1994, among JMC 				Selkirk, Inc. ("JMC Selkirk"), JMCS I, Investors, L.P. ("JMCS 				I Investors"), Makowski Selkirk Holdings, Inc. ("Makowski 				Selkirk"), Cogen Technologies Selkirk, LP ("Cogen 				Technologies LP") and Cogen Technologies Selkirk GP, Inc. 				("Cogen Technologies GP")
3.5(2)			Amendment No. 1 to the Third Amended and Restated Agreement 				of Limited Partnership of the Partnership, dated as of 				November 1, 1994
3.6(2)			Amendment No. 2 to the Third Amended and Restated Agreement 				of Limited Partnership of the Partnership, dated as of June 				16, 1995
4.1(1)			Trust Indenture, dated as of May 1, 1994, among the Funding 				Corporation, the Partnership and Bankers Trust Company, as 				trustee (the "Trustee")
4.2(1)			First Series Supplemental Indenture, dated as of May 1, 1994, 				among the Funding Corporation, the Partnership and the 				Trustee
4.3(1)			Registration Agreement, dated April 29, 1994, among the 				Funding Corporation, the Partnership, CS First Boston 				Corporation, Chase Securities, Inc. and Morgan Stanley & Co. 				Incorporated
4.4(1)			Partnership Guarantee, dated as of May 1, 1994, of the 				Partnership to the Trustee (2007)
4.5(1)			Partnership Guarantee, dated as of May 1, 1994, of the 				Partnership to the Trustee (2012)
10.1			Credit Facilities
10.1.1(1) 		Credit Bank Working Capital and Reimbursement Agreement, 				dated as of May 1, 1994, among the Partnership, The Chase 				Manhattan Bank, N.A. ("Chase"), as Agent, and the other 				Credit Banks identified therein
10.1.2(1)		Amendment No. 1 to Credit Agreement, dated August 11, 1994, 				among the Partnership, Dresdner Bank AG, New York Branch, and 				Chase
10.1.3(1)		Loan Agreement, dated as of May 1, 1994, between the 				Partnership, Chase, as Agent, and other Bridge Banks 				identified therein
10.1.4(1)		Amended and Restated Loan Agreement, dated as of May 1, 1994, 				between the Funding Corporation and the Partnership
10.1.5(1)		Agreement of Consolidation, Modification and Restatement of 				Notes ($227,000,000), dated as of May 1, 1994, between the 				Partnership and the Funding Corporation, together with 				Endorsement from the Funding Corporation dated May 9, 1994
10.1.6(1)		Agreement of Consolidation, Modification and Restatement of 				Notes ($165,000,000), dated as of May 1, 1994, between the 				Partnership and the Funding Corporation, together with 				Endorsement from the Funding Corporation dated May 9, 1994
10.2			Power Purchase Agreements
10.2.1(1)		Power Purchase Agreement, dated as of December 7, 1987, 				between JMC Selkirk and Niagara Mohawk Power Corporation 				("Niagara Mohawk")
10.2.2(1)		Amendment to Power Purchase Agreement, dated as of December 				14, 1989, between JMC Selkirk and Niagara Mohawk
10.2.3(1)		Second Amendment to Power Purchase Agreement, dated as of 				January, 25, 1990, between JMC Selkirk and Niagara Mohawk
10.2.4(1)		Third Amendment to Power Purchase Agreement, dated as of 				October 23, 1992 between JMC Selkirk and Niagara Mohawk
10.2.5(4)		Fourth Amendment to Power Purchase Agreement, dated as of 				June 26, 1996 between the Partnership and Niagara Mohawk
10.2.6(1)		Agreement dated as of March 31, 1994, between the Partnership 				and Niagara Mohawk
10.2.7(1)		Termination of the Subordination Agreement and the Assignment 				of Contracts and Security Agreement, as amended, dated May 9, 				1994, among Niagara Mohawk, Chase, as Agent, and the 				Partnership
10.2.8(1)		License Agreement between the Partnership and Niagara Mohawk, 				dated as of October 23, 1992
10.2.9(1)		Power Purchase Agreement, dated as of April 14, 1989, between 				Con Edison Company of New York, Inc. ("Con Edison") and JMC 				Selkirk
10.2.10(1)		Rider to Power Purchase Agreement, dated as of September 13, 				1989, between Con Edison and JMC Selkirk
10.2.11(1)		First Amendment to Power Purchase Agreement, dated as of 				September 13, 1991, between Con Edison and JMC Selkirk
10.2.12(1)		Letter Agreement Regarding Extending the Term of the Power 				Purchase Agreement, dated as of May 28, 1992, between Con 				Edison and JMC Selkirk
10.2.13(1)		Second Amendment to Power Purchase Agreement, dated as of 				October 22, 1992, between Con Edison and JMC Selkirk
10.2.14(5)		Third Amendment to Power Purchase Agreement, dated as of 				September 13, 1996, between Con Edison and the Partnership
10.2.15(1)		Letter Agreement Regarding Arbitration, dated October 22, 				1992, between Con Edison and JMC Selkirk
10.2.16(1)		Letter Agreement Regarding Sale of Capacity above 265 MW, 				dated as of October 22, 1992, between Con Edison and JMC 				Selkirk
10.2.17(1)		Notice, Certificate and Waiver of Con Edison for assignment 				by Selkirk Cogen Partners, L.P. ("SCP II") to the Partnership 				pursuant to the merger, dated October 19, 1992
10.2.18(1)		Letter Agreement regarding Alternative Fuel Supply, dated as 				of July 29, 1994, between Con Edison and the Partnership
10.3			Construction Agreements
10.3.1(1)		Engineering, Procurement and Construction Services Agreement, 				dated as of October 21, 1992, between the Partnership and 				Bechtel Construction of Nevada and Bechtel Associates 				Professional Corporation (the "Contractor")
10.4			Steam Agreements
10.4.1(1)		Agreement for the Sale of Steam, dated as of October 21, 				1992, between the Partnership and General Electric Company 				("General Electric")
10.4.2(1) 		Amendment to Steam Sales Agreement, dated as of August 12, 		 		1993, between the Partnership and General Electric
10.4.3(1)		Amended and Restated Operation and Maintenance Agreement, 				dated as of October 22, 1992, between the Partnership and 				General Electric
10.4.4(1)		Second Amendment to Steam Sales Agreement, dated December 7, 				1994, between the Partnership and General Electric
10.4.5(2)		Third Amendment to Steam Sales Agreement, dated May 31, 1995, 				between the Partnership and General Electric
10.5			Fuel Supply Contracts
10.5.1(1)		Amended and Restated Gas Purchase Contract, dated as of 				September 26, 1992, between Paramount Resources Ltd. 				("Paramount") and the Partnership
10.5.2(1)		First Amendment to the Amended and Restated Gas Purchase 				Contract, dated as of October 5, 1992, between Paramount and 				the Partnership
10.5.3(1)		Letter Agreement, dated as of October 25, 1993, between the 				Partnership and Paramount
10.5.4(1)		Second Amendment to the Amended and Restated Gas Purchase 				Contract, dated as of December 1, 1993, between Paramount and 				the Partnership
10.5.5(1)		Indemnity Agreement, dated as of February 20, 1989, by the 				Partnership in favor of Paramount
10.5.6(1)		Letter Agreement, dated as of June 11, 1990, between the 				Partnership and Paramount
10.5.7(1)		Indemnity Amending and Supplemental Agreement, dated as of 				June 19, 1990, between the Partnership and Paramount
10.5.8(1)		Intercreditor Agreement, dated as of October 21, 1992, 				between Paramount, the Partnership and Chase, as Agent
10.5.9(1)		Specific Assignment of Unit 1 TransCanada Transportation 				Contract, dated as of December 20, 1991, by the Partnership 				to Paramount
10.5.10(1)		Amendment No. 1 to Specific Assignment, dated as of October 				21, 1992, between the Partnership and Paramount
10.5.11(1)		Amended and Restated Gas Purchase Agreement, dated as of 				January 21, 1993, between the Partnership and Atcor Ltd. 				("Atcor")
10.5.12(1)		Amended and Restated Gas Purchase Agreement, dated as of 				October 22, 1992, between the Partnership, as assignee, and 				Imperial Oil Resources ("Imperial")
10.5.13(1)		Amended and Restated Gas Purchase Agreement, dated as of 				October 22, 1992, between the Partnership, as assignee, and 				PanCanadian Pertroleum Limited ("PanCanadian")
10.5.14(1)		Back-up Fuel Supply Agreement, dated as of June 18, 1992, 				between Phibro Energy USA, Inc. ("Phibro") and SCP II
10.6			Fuel Transportation Agreements
10.6.1(1)		Gas Transportation Contract for Firm Reserved Service, dated 				as of February 7, 1991, between Iroquois Gas Transmission 				System, L.P. ("Iroquois") and the Partnership
10.6.2(1)		Letter Agreement, dated June 30, 1993, from Iroquois and 				acknowledged and accepted for the Partnership by JMC Selkirk
10.6.3(1)		Firm Service Contract for Firm Transportation Service, dated 				as of September 6, 1991, between TransCanada PipeLines 				Limited ("TransCanada") and the Partnership
10.6.4(1)		Amending Agreement, dated as of May 28, 1993, between the 				Partnership and TransCanada
10.6.5(1)		Firm Natural Gas Transportation Agreement, dated as of April 				18, 1991, between Tennessee Gas Pipeline and the Partnership
10.6.6(1)		Clarification Letter from Tennessee, dated April 18, 1991, 				between the Partnership and Tennessee
10.6.7(1)		Supplemental Agreement (Unit 1), dated April 18, 1991, 				between the Partnership and Tennessee
10.6.8(1)		Operational Balancing Agreement, dated as of September 1, 				1993, between the Partnership and Tennessee
10.6.9(1)		Interruptible Transportation Agreement, dated as of September 				1, 1993, between the Partnership and Tennessee
10.6.10(1)		License Agreement for the Ten-Speed 2 System, dated as of 				July 21, 1993, between the Partnership, Tennessee, Midwestern 				Gas Transmission Company and East Tennessee Natural Gas 				Company
10.6.11(1)		Firm Service Contract for Firm Transportation Service, dated 				as of March 16, 1994, between the Partnership and TransCanada
10.6.12(1)		Letter Agreement, dated as of March 24, 1994, between the 				Partnership and TransCanada
10.6.13(1)		Gas Transportation Contract for Firm Reserved Service, dated 				as of April 5, 1994, between the Partnership and Iroquois
10.6.14(1)		Letter Agreement, dated as of March 31, 1994, between the 				Partnership and Iroquois
10.6.15(1)		Firm Natural Gas Transportation Agreement, dated as of April 				11, 1994, between the Partnership and Tennessee
10.6.16(1)		Tennessee Supplemental Agreement (Unit 2), dated as of 				October 21, 1992, between Tennessee and the Partnership
10.6.17(1)		Letter Agreement, dated September 22, 1993, between the 				Partnership and Tennessee
10.6.18(2)		Consent and Agreement, dated May 15, 1995, between the 				Partnership, Iroquois and the Trustee
10.7			Transmission and Interconnection Agreements
10.7.1(1)		Transmission Services Agreement, dated as of December 13, 				1990, between Niagara Mohawk and SCP II
10.7.2(1)		Notice, Certificate, Agreement, Waiver and Acknowledgment to 				Niagara Mohawk of Assignment of Transmission Agreement to the 				Partnership, dated as of October 23, 1992
10.7.3(1)		Interconnection Agreement (Unit 1), dated as of October 20, 				1992, between Niagara Mohawk and SCP II
10.7.4(1)		Interconnection Agreement (Unit 2), dated as of October 20, 				1992, between Niagara Mohawk and SCP II
10.8			Administrative Services Agreements and Water Supply Agreement
10.8.1(1)		Project Administrative Services Agreement, dated as of June 				15, 1992, between JMCS I Management, Inc. ("JMCS I 				Management") and the Partnership
10.8.2(1)		First Amendment to Project Administrative Services Agreement, 				dated as of October 23, 1992, between JMCS I Management and 				the Partnership
10.8.3(1)		Second Amendment to Project Administrative Services 				Agreement, dated as of May 1, 1994, between JMCS I Management 				and the Partnership
10.8.4(1)		Water Supply Agreement, dated as of May 6, 1992, between the 				Town of Bethlehem, New York and the Partnership
10.9			Real Estate Documents
10.9.1(1)		Second Amended and Restated Lease Agreement, dated as of 				October 21, 1992, between the Partnership and General 				Electric
10.9.2(1)		Amended and Restated First Amendment to Second Amended and 				Restated Lease Agreement, dated as of April 30, 1994, between 				the Partnership and General Electric
10.9.3(1)		Unit 2 Grant of Easement, dated as of October 21, 1992, made 				by General Electric in favor of the Partnership (regarding 				Unit 2 Substation and Transmission Line)
10.9.4(1)		Declaration of Restrictive Covenants by General Electric, 				dated as of October 21, 1992 (regarding Wetlands Remediation 				Areas)
10.9.5(1)		Utilities Building Lease Agreement, dated as of October 21, 				1992, between General Electric, as Landlord, and the 				Partnership, as Tenant
10.9.6(1)		Easement Agreement, dated as of May 27, 1992, between Charles 				Waldenmaier and the Partnership, as assignee
10.9.7(1)		Facility Lease Agreement, dated as of October 21, 1992, 				between the Partnership, as Landlord, and the Town of 				Bethlehem, New York Industrial Development Agency ("IDA"), as 				Tenant
10.9.8(1)		Amended and Restated First Amendment to Facility Lease 				Agreement, dated as of April 30, 1994, between the 				Partnership and the IDA 	 	 10.9.9(1)		Sublease Agreement, dated as of October 21, 1992, between the 				Partnership, as Subtenant, and the IDA, as Sublandlord
10.9.10(1)		Amended and Restated First Amendment to Sublease Agreement, 				dated as of April 30, 1994, between the Partnership and the 				IDA
10.9.11(1)		Payment in Lieu of Taxes Agreement, dated as of October 21, 				1992, between the Partnership and the IDA
10.10			Security Documents
10.10.1(1)		Assignment of Agreements, dated as of May 1, 1994, among 				Yasuda Bank and Trust Company (U.S.A.) ("Yasuda"), Dresdner 				Bank AG, New York and Grand Cayman Branches ("Dresdner"), the 				Depositary Agent, the Collateral Agent, the Partnership and 				the Funding Corporation
10.10.2(1)		Depositary Agreement, dated as of May 1, 1994, among the 				Funding Corporation, the Partnership, Bankers Trust Company 				as collateral agent ("Collateral Agent") and Bankers Trust 				Company, as depositary agent (the "Depositary Agent")
10.10.3(1)		Equity Contribution Agreement, dated as of May 1, 1994, among 				the Partnership, Cogen LP, Cogen GP, Makowski Selkirk and 				Chase
10.10.4(1)		Cash Collateral Agreement, dated as of May 1, 1994, among 				Makowski Selkirk, the Partnership and Chase, as Agent
10.10.5(1)		Cash Collateral Agreement, dated as of May 1, 1994, among 				Cogen LP, the Partnership and Chase, as Agent
10.10.6(1)		Cash Collateral Agreement, dated as of May 1, 1994, among 				Cogen GP, the Partnership and Chase, as Agent
10.10.7(1)		Agreement of Spreader, Consolidation and Modification of 				Leasehold Mortgages, Security Agreements and Fixture 				Financing Statements, (the "First Consolidated Mortgage"), 				dated as of May 1, 1994, in the principal amount of 				$227,000,000 among the Partnership, the IDA and the 				Collateral Agent
10.10.8(1)		Agreement of Spreader, Consolidation and Modification of 				Leasehold Mortgages, Security Agreements and Fixture 				Financing Statements, dated as of May 1, 1994, in the 				principal amount of $122,000,000 among the Partnership, the 				IDA and the Collateral Agent
10.10.9(1)		Agreement of Spreader and Modification of Leasehold Mortgage 				(the "Restated Mortgage"), dated as of May 1, 1994, in the 				principal amount of $43,000,000 among the Partnership, the 				IDA and the Collateral Agent
10.10.10(1)		Agreement of Modification and Severance of Mortgage (the 				"Mortgage Splitter Agreement"), dated as of May 1, 1994, 				among the Partnership, the IDA and the Collateral Agent
10.10.11(1)		Leasehold Mortgage (Substitute Mortgage No. 1), dated as of 				May 1, 1994, in the principal amount of $9,099,000 given by 				the Partnership and the IDA to the Collateral Agent
10.10.12(1)		Leasehold Mortgage (Substitute Mortgage No. 2), dated as of 				May 1, 1994, in the principal amount of $43,000,000 given by 				the Partnership and the IDA to the Collateral Agent
10.10.13(1)		Leasehold Mortgage (Substitute Mortgage No. 1), dated as of 				May 1, 1994, in the principal sum of $16,601,000 given by the 				Partnership and the IDA to the Collateral Agent
10.10.14(1)		Leasehold Mortgage (Gap Mortgage No. 2) in the principal 				amount of $42,199,000, dated as of May 1, 1994, given by the 				Partnership and the IDA to the Collateral Agent
10.10.15(1)		Leasehold Mortgage, Security Agreement and Fixture Financing 				Statement (the "Chase Mortgage"), dated as of May 1, 1994, 				given by the Partnership and the IDA to the Collateral Agent
10.10.16(1)		Amended and Restated Security Agreement and Assignment of 				Contracts (the "Security Agreement"), dated as of May 1,1994, 				made by the Partnership in favor of the Collateral Agent
10.10.17(1)		Pledge and Security Agreement (the "Partnership Pledge 				Agreement"), dated as of May 1, 1994, from the Partnership in 				favor of the Collateral Agent
10.10.18(1)		Security Agreement (the "Company Security Agreement"), dated 				as of May 1, 194, from the Company in favor of the Collateral 				Agent
10.10.19(1)		Intercreditor Agreement, dated as of May 1, 1994, among the 				Trustee, the Credit Bank, the Funding Corporation, the 				Partnership, the Collateral Agent and certain other parties
10.10.20(1)		Purchase Agreement and Transfer Supplement, dated as of May 				1, 1994, among Chase, Dresdner, Yasuda, the Funding 				Corporation and the Partnership
10.11			Other Material Project Contracts
10.11.1(1)		Purchase Agreement, dated April 29, 1994, among the Funding 				Corporation, the Partnership, CS First Boston Corporation, 				Chase Securities, Inc. and Morgan Stanley & Co. Incorporated
10.11.2(1)		Capital Contribution Agreement, dated as of April 28, 1994, 				among the Partnership, JMC Selkirk, JMCS I Investors, Cogen 				Technologies GP and Cogen Technologies LP (collectively, the 				"Partners")
10.11.3(1)		Equity Depositary Agreement, dated as of May 1, 1994, among 				the Partnership, the Partners, Makowski Selkirk and Citibank, 				N.A. as Special Agent
16(3)			Letter from former accountant (Ernst & Young, LLP), dated as 				of February 13, 1995, to the Securities and Exchange 				Commission regarding the Partnership's change in certifying 				accountant.
21(1)			Subsidiaries of the Funding Corporation and Partnership
27				Financial Data Schedule (for electronic filing purposes only)
- ------------------- (1) Incorporated herein by reference to the Registrant's Registration Statement on Form S-1 filed September 1, 1994, as amended (File No. 33-83618).
(2) Incorporated herein by reference to the Registrant's Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1995 filed August 14, 1995.
(3) Incorporated herein by reference to the Registrant's Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1995 filed March 29, 1996.
(4) Incorporated herein by reference to the Registrant's Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1996 filed August 13, 1996.
(5) Incorporated herein by reference to the Registrant's Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 1996 filed November 14, 1996.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
	 SELKIRK COGEN PARTNERS, L.P. 						
Date: March 31, 1997	 /s/ JMC SELKIRK, INC. -------------------------- 	 General Partner
Date: March 31, 1997	 /s/ JOHN R. COOPER -------------------------- 	 Name: John R. Cooper Title:	Senior Vice President and 		 and Chief Financial Officer 			 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
Signature			 	 Title			 		 Date 	 ----------- ------ ------
/s/ JOSEPH P. KEARNEY		Chief Executive Officer,		March 31, 1997 - ---------------------		 President and Director Joseph P. Kearney 						 /s/	P. CHRISMAN IRIBE	 Executive Vice President		March 31, 1997 - --------------------- and Director P. Chrisman Iribe
/s/ JOHN R. COOPER Senior Vice President and March 31, 1997 - --------------------- Chief Financial Officer John R. Cooper
/s/ DAVID N. BASSETT		Treasurer						March 31, 1997 - --------------------- David N. Bassett
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
	 SELKIRK COGEN FUNDING 										 CORPORATION 						
Date: March 31, 1997	 /s/ JOHN R. COOPER -------------------------- 	 Name: John R. Cooper Title:	Senior Vice President and 		 and Chief Financial Officer 			 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
Signature					 Title					 Date 	 ---------- ------- ------
/s/ JOSEPH P. KEARNEY		Chief Executive Officer,		March 31, 1997 - ---------------------		 President and Director Joseph P. Kearney 						 /s/	P. CHRISMAN IRIBE	 Executive Vice President		March 31, 1997 - --------------------- and Director P. Chrisman Iribe
/s/ JOHN R. COOPER Senior Vice President and March 31, 1997 - --------------------- Chief Financial Officer John R. Cooper
/s/ DAVID N. BASSETT		Treasurer						March 31, 1997 - --------------------- David N. Bassett