FORM 10-Q

[X]       QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2003

Commission File Number 33-83618

SELKIRK COGEN PARTNERS, L.P.
(Exact name of Registrant (Guarantor) as specified in its charter)

               

SELKIRK COGEN FUNDING CORPORATION
(Exact name of Registrant as specified in its charter)

7600 Wisconsin Avenue (Mailing Address: 7500 Old Georgetown Road) , Bethesda, Maryland 20814
  (Address of principal executive offices, including zip code)

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

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

                Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.          Yes  X  No __

                Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).                 Yes __  No X

                As of May 12, 2003, there were 10 shares of common stock of Selkirk Cogen Funding Corporation, $1 par value outstanding.

TABLE OF CONTENTS

PART I.  FINANCIAL INFORMATION

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SELKIRK COGEN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1. Basis of Presentation

The accompanying unaudited consolidated financial statements include Selkirk Cogen Partners, L.P. and its wholly-owned subsidiary, Selkirk Cogen Funding Corporation (collectively the “Partnership”).  All significant intercompany accounts and transactions have been eliminated.

The consolidated financial statements for the interim periods presented are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted pursuant to rules and regulations applicable to interim financial statements. The information furnished in the consolidated financial statements reflects all normal recurring adjustments, which, in the opinion of management, are necessary for a fair presentation of such financial statements.  Certain reclassifications have been made to the consolidated statement of operations for the three months ended March 31, 2002 to conform with the current period's basis of presentation.  Operating results for the three months ended March 31, 2003 are not necessarily indicative of the results that may be expected for the year ended December 31, 2003.

These consolidated financial statements should be read in conjunction with the audited consolidated financial statements included in the Partnership’s December 31, 2002 Annual Report on Form 10-K.

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

Comprehensive Income

The Partnership’s comprehensive income consists principally of net income and changes in the market value of certain financial hedges under Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities (collectively, “SFAS No. 133”).

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The schedule below summarizes the activities affecting comprehensive income for the three months ended March 31, 2003 and 2002 (in thousands):

Note 2. Significant Accounting Policies

Except as disclosed, the Partnership is following the same accounting principles discussed in the Partnership’s December 31, 2002 Annual Report on Form 10-K.

Adoption of New Accounting Pronouncements

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

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

If this statement had been adopted on January 1, 2002, the pro forma effects on earnings of the accounting change for the three months ended March 31, 2002 would not have been material. 

In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, which is effective for exit and deposal activities initiated after December 31, 2002.  In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.  This interpretation establishes new disclosure requirements for all guarantees, but the measurement criteria are applicable to guarantees issued and modified after December 31, 2002.  This statement and interpretation was adopted on January 1, 2003 and did not have an impact on the Partnership’s consolidated financial statements.

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Accounting Principles Issued But Not Yet Adopted

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities.  This interpretation applies to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date.  For variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003, application begins in the first fiscal year or interim period beginning after June 15, 2003.  The Partnership does not expect that implementation of this interpretation will have a significant impact on its consolidated financial statements.

In April 2003, the FASB issued Statement No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS No. 149”).  SFAS No. 149 amends and clarifies the accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133.  The amendments set forth in SFAS No. 149 require that contracts with comparable characteristics be accounted for similarly.  In particular, this statement clarifies under what circumstances a contract with an initial net investment meets the characteristics of a derivative according to SFAS No. 133 and when a derivative contains a financing component that warrants special reporting in the statement of cash flows. 

The requirements of SFAS 149 are effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003.  The provisions of the statement that relate to previous FASB guidance issued in the form of SFAS No. 133 Implementation Issues that have been effective for fiscal quarters that began prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates.  The Partnership is currently evaluating the impacts, if any, of SFAS 149 on its consolidated financial statements.

Note 3. Related Party Transactions

JMCS I Management, Inc. manages the day-to-day operation of the Partnership and is compensated at agreed-upon billing rates that are adjusted quadrennially in accordance with an administrative services agreement.  The cost of services provided by JMCS I Management, Inc. are included in administrative services – affiliates in the accompanying consolidated statements of operations.  The total amount due to JMCS I Management, Inc. for these services at March 31, 2003, was approximately $276,000.

The Partnership purchases from and sells gas to PG&E Energy Trading – Gas Corporation (“PG&E Energy Trading – Gas”), PG&E Energy Trading – Canada Corporation (“PG&E Energy Trading – Canada”), Pittsfield Generating Company, L.P. (“Pittsfield Generating”), and MASSPOWER, affiliates of JMC Selkirk, Inc., at fair value.  Gas purchases are recorded as fuel costs and sales of gas are recorded as fuel revenues in the accompanying consolidated statements of operations.  The net amount due to PG&E Energy Trading – Gas at March 31, 2003, was approximately $784,000.  At March 31, 2003, PG&E Energy Trading – Canada is no longer a related party.

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

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

In May 1996, the Partnership entered into an enabling agreement with PG&E Energy Trading – Power, L.P. (PG&E Energy Trading – Power”) to purchase and sell electric capacity, electric energy, and other services.  There were no sales of energy, capacity and other services for the three months ended March 31, 2003, compared to approximately $1,293,000 for the same period in the prior year.  There was no amount due from PG&E Energy Trading – Power at March 31, 2003.

The Partnership has two agreements with Iroquois Gas Transmission System (“IGTS”), an indirect affiliate of JMC Selkirk, Inc., to provide firm transportation of natural gas from Canada.  Firm fuel transportation services for the three months ended March 31, 2003 totaled approximately $1,774,000, compared to approximately $1,802,000 for the same period in the prior year.  These services are recorded as fuel costs in the accompanying consolidated statements of operations.  The total amount due to IGTS for firm transportation at March 31, 2003, was approximately $599,000.

Note 4. Accounting For Derivative Contracts

Currency Exchange Contracts

The Partnership has two foreign currency exchange contracts to hedge against fluctuations in fuel transportation costs, which are denominated in Canadian dollars.  Under the Unit 1 currency exchange agreement, which had a term of ten years and expired on December 25, 2002, the Partnership exchanged approximately $368,000 U.S. dollars for $458,000 Canadian dollars on a monthly basis.  Under the Unit 2 currency exchange agreement, which commenced on May 25, 1995 and terminates on December 25, 2004, the Partnership exchanges approximately $1,044,000 U.S. dollars for $1,300,000 Canadian dollars on a monthly basis.   The Partnership accounts for its foreign exchange contracts as cash flow hedges and has recorded on the consolidated balance sheets a liability for derivative contracts with the offset in other comprehensive income (loss).

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The amount charged to fuel costs as a result of losses realized from these contracts for the three months ended March 31, 2003 totaled approximately $487,000, compared to approximately $872,000 for the same period in the prior year.  The Partnership expects that net derivative losses of approximately $1,885,000, included in accumulated other comprehensive loss as of March 31, 2003, will be reclassified into earnings within the next twelve months.

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

Peak shaving arrangements

The Partnership enters into peak shaving arrangements whereby it grants to local distribution companies or other purchasers a call on a specified portion of the Partnership’s firm natural gas supply for a specified number of days during the winter season.  Such arrangements are derivatives under SFAS No. 133.  Changes in the fair value of these peak shaving arrangements are recorded on the consolidated statements of operations as an unrealized gain or loss on derivative contracts.  The unrealized loss on derivative contracts for the three months ended March 31, 2002 was approximately $446,000.

  

Note 5. Concentrations of Credit Risk

Credit risk is the risk of loss the Partnership would incur if counterparties fail to perform their contractual obligations (accounts receivable and due from affiliates).  The Partnership primarily conducts business with customers in the energy industry, such as investor-owned utilities, energy trading companies, financial institutions, gas production companies and gas transportation companies located in the United States and Canada.  This concentration of counterparties may impact the Partnership’s overall exposure to credit risk in that its counterparties may be similarly affected by changes in economic, regulatory or other conditions.  The Partnership mitigates potential credit losses in accordance with established credit approval practices and limits by dealing primarily with counterparties it considers to be of investment grade.

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As of March 31, 2003, the Partnership’s credit risk is primarily concentrated with the following customers: Consolidated Edison Company of New York, Inc., Niagara Mohawk Power Corporation and the New York Independent System Operator, all of whom are considered to be of investment grade. 

Note 6. Relationship with PG&E Corporation and PG&E National Energy Group, Inc.

JMC Selkirk, Inc. is the managing general partner of the Partnership.  Approximately 90% of the ownership interest in JMC Selkirk, Inc. is held by an indirect subsidiary of PG&E National Energy Group, Inc. ("NEG").  NEG is an indirect, wholly owned subsidiary of PG&E Corporation, the parent company of Pacific Gas and Electric Company (the "Utility"). 

In December 2000, and January and February 2001, PG&E Corporation and NEG completed a corporate restructuring of NEG that involved the use or creation of limited liability companies (“LLCs”) as intermediate owners between a parent company and its subsidiaries.  One of these LLCs is PG&E National Energy Group, LLC, which owns 100% of the stock of NEG. 

On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the United States Bankruptcy Court for the Northern District of California (“Bankruptcy Court”).  Pursuant to the Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court.  The Utility and PG&E Corporation jointly filed a plan of reorganization with the Bankruptcy Court that entails separating the Utility into four distinct businesses.  The proposed plan of reorganization does not directly affect NEG or any of its subsidiaries.  The Managing General Partner believes that NEG and its direct and indirect subsidiaries, including JMC Selkirk, Inc., PentaGen Investors, L.P., and the Partnership, would not be substantively consolidated with PG&E Corporation in any insolvency or bankruptcy proceeding involving PG&E Corporation or the Utility.

As a result of the sustained downturn in the power industry, NEG and certain of its affiliates have experienced a financial downturn, which caused the major credit rating agencies to downgrade NEG and certain of its affiliates’ credit ratings to below investment grade.  The credit rating agency action has had no material impact on the financial condition or results of operations of the Partnership. 

On October 8, 2002, Moody’s Investor Services (“Moody’s”) stated that in conjunction with the downgrade of NEG it had placed the Partnership’s debt under review for possible downgrade.  On October 15, 2002, Standard and Poor’s (“S&P”) stated that the recent downgrade of NEG will not have an affect on the rating of the Partnership’s debt at this time.  S&P’s rating of the Partnership’s debt is “BBB-”.  On November 5, 2002, Moody’s issued an opinion update changing the rating outlook of the Partnership’s debt to “under review for possible downgrade” from “stable” for the Partnership’s debt due in 2007 and “negative outlook” for the Partnership’s debt due in 2012.  Moody’s rating of the Partnership’s debt is “Baa3”.  A downgrade of the credit ratings of the Partnership's debt due in 2007 or 2012 by S&P or Moody's (or both) would not be an event of default under any of the Partnership's debt agreements and material project contracts or otherwise result in an adverse change to any material term of such agreements and contracts.

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NEG and certain affiliates are currently in default under various debt agreements and guaranteed equity commitments.  NEG, its subsidiaries and their lenders have been engaged in discussions to restructure NEG’s and its subsidiaries’ debt obligations and other commitments since October 2002.  No agreement has been reached yet and there can be no assurance that an agreement will be reached.  Any restructuring agreement that may be reached would be implemented through a reorganization proceeding under Chapter 11 of the U.S. Bankruptcy Code.  None of JMC Selkirk, Inc., PentaGen Investors, L.P. or the Partnership are parties to such debt agreements and guaranteed equity commitments or participants in such discussions. 

Although NEG and its subsidiaries are continuing their efforts to maximize cash and reduce liabilities, such efforts are not expected to restore the financial condition of NEG and its subsidiaries.  Absent a negotiated agreement, the lenders may exercise their default remedies or force NEG and certain of its subsidiaries into an involuntary proceeding under the U.S. Bankruptcy Code.  Notwithstanding the status of current negotiations, NEG and certain of its subsidiaries also may elect to voluntarily seek protection under the U.S. Bankruptcy Code as early as the second quarter 2003.

NEG owns an indirect interest in the Partnership, and through its indirect, wholly owned subsidiaries, JMC Selkirk, Inc. and JMCS I Management, Inc., manages the Partnership.  The Partnership cannot be certain that an insolvency or bankruptcy involving NEG or any of its subsidiaries would not affect NEG’s ownership arrangements with respect to the Partnership or the ability of JMC Selkirk, Inc. or JMCS I Management, Inc. to manage the Partnership.  The Partnership Agreement provides certain management rights to RCM Selkirk GP, Inc. in the event that JMC Selkirk, Inc. were to be included in a bankruptcy involving NEG, including (i) the removal of JMC Selkirk, Inc. as the managing general partner, (ii) the appointment of itself as the successor managing general partner, and (iii) the termination of the administrative services agreement with JMCS I Management, Inc. and subsequent appointment of a RCM Selkirk GP, Inc. affiliate as the project management firm.  Enforcement of these rights by RCM Selkirk GP, Inc. could, however, be delayed or impeded as a result of any bankruptcy proceeding involving JMC Selkirk, Inc.  Moreover, the bankruptcy of any partner of the Partnership would be an event of default under the Partnership’s Credit Agreement.  Currently, the Partnership has contingent reimbursement obligations arising under letters of credit issued under this Credit Agreement in the amount of approximately $2.5 million, which the Partnership believes could be secured with cash collateral financed with cash flows from operations. 

Note 7. Title V Permit

On November 6, 2001, the Partnership received from the New York State Department of Environmental Conservation (“DEC”) the Facility's Title V operating permit endorsed by the DEC on November 2, 2001 (the "Title V Permit”).  The Title V Permit as

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

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Partnership’s consolidated financial statements and notes to the consolidated financial statements included herein.  Further, this Quarterly Report on Form 10-Q should be read in conjunction with the Partnership’s 2002 Annual Report on Form 10-K.

Cautionary Statement Regarding Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q includes forward-looking statements about the future that are necessarily subject to various risks and uncertainties.  Use of words like “anticipate,” “estimate,” “intend,” “project,” “plan,” “expect,” “will,” “believe,” “could,” and similar expressions help identify forward-looking statements.  These statements are based on current expectations and assumptions which the Partnership believes are reasonable and on information currently available to the Partnership.  Actual results could differ materially from those contemplated by the forward-looking statements.  Although the Partnership believes that the expectations reflected in the forward-looking statements are reasonable, future results, events, levels of activity, performance or achievements cannot be guaranteed.  Although the Partnership is not able to predict all the factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements include:

Operational Risks

The Partnership’s future results of operations and financial condition may be affected bythe performance of equipment; levels of dispatch; the receipt of certain capacity and other fixed payments; electricity prices; natural gas resale prices; fuel deliveries and prices; and whether PG&E National Energy Group, Inc. (“NEG”) and certain of its subsidiaries seek protection under the U.S. Bankruptcy Code, or are forced into a proceeding under the U.S. Bankruptcy Code.

Potential Collateral Requirements

The Partnership’s future results of operations and financial condition may be affected if its credit agreement is not renewed or replaced, which would require the Partnership to secure its current letters of credit and any requests for additional assurances with cash collateral.

Accounting and Risk Management

The Partnership’s future results of operations and financial condition may be affected by the effect of new accounting pronouncements; changes in critical accounting policies or estimates; the effectiveness of the Partnership’s risk management policies and procedures; the ability of the Partnership’s counterparties to satisfy their financial

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commitments to the Partnership and the impact of counterparties’ nonperformance on the Partnership’s liquidity position; and heightened rating agency criteria and the impact of changes in the Partnership’s credit ratings.

Legislative and Regulatory Matters

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

Litigation and Environmental Matters

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

Overview

The Partnership owns a natural gas-fired, combined-cycle cogeneration facility consisting of two unitsdesigned to operate independently for electrical generation, but thermally integrated for steam generation.  Revenues are derived primarily from sales of electricity and, to a lesser extent, from sales of steam and natural gas.  Sales of natural gas typically occur when a unit is dispatched off-line or at less than full capacity (“Gas Resales”).  In addition, sales of natural gas may also occur when the Partnership is able to optimize the long-term gas supply and transportation contracts and lower the cost of natural gas delivered to the Facility by purchasing and/or selling natural gas at favorable prices along the transportation route (“Gas Optimizations”).   During the first quarter of 2003, natural gas resale prices and the price of natural gas under the firm gas supply contracts have been higher than prices during the first quarter of 2002.  The Partnership can not predict whether such prices will remain above 2002 levels for the balance of 2003.

The Facility will typically be scheduled on an economic basis, which takes into account the variable cost of electricity to be delivered by each unit compared to the variable cost of electricity available to the purchaser from other sources.  At times, a unit will be dispatched off-line to perform scheduled maintenance.  Differences in the timing and scope of scheduled maintenance can have a significant impact on revenues and the cost of revenues.  The Facility has scheduled four weeks of non-major maintenance outages during 2003.

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Relationship with PG&E Corporation and NEG

JMC Selkirk, Inc. is the managing general partner of the Partnership.  Approximately 90% of the ownership interest in JMC Selkirk, Inc. is held by an indirect subsidiary of NEG.  NEG is an indirect, wholly owned subsidiary of PG&E Corporation, the parent company of Pacific Gas and Electric Company (the "Utility"). 

In December 2000, and January and February 2001, PG&E Corporation and NEG completed a corporate restructuring of NEG that involved the use or creation of limited liability companies (“LLCs”) as intermediate owners between a parent company and its subsidiaries.  One of these LLCs is PG&E National Energy Group, LLC, which owns 100% of the stock of NEG. 

On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the United States Bankruptcy Court for the Northern District of California (“Bankruptcy Court”).  Pursuant to the Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court.  The Utility and PG&E Corporation have jointly filed a plan of reorganization with the Bankruptcy Court that entails separating the Utility into four distinct businesses.  The proposed plan of reorganization does not directly affect NEG or any of its subsidiaries.  The Managing General Partner believes that NEG and its direct and indirect subsidiaries, including JMC Selkirk, Inc., PentaGen Investors, L.P., and the Partnership, would not be substantively consolidated with PG&E Corporation in any insolvency or bankruptcy proceeding involving PG&E Corporation or the Utility.

As a result of the sustained downturn in the power industry, NEG and certain of its affiliates have experienced a financial downturn, which caused the major credit rating agencies to downgrade NEG and certain of its affiliates’ credit ratings to below investment grade.  The credit rating agency action has had no material impact on the financial condition or results of operations of the Partnership.  (See “Credit Ratings” below)

NEG and certain affiliates are currently in default under various debt agreements and guaranteed equity commitments.  NEG, its subsidiaries and their lenders have been engaged in discussions to restructure NEG’s and its subsidiaries’ debt obligations and other commitments since October 2002.  No agreement has been reached yet and there can be no assurance that an agreement will be reached.  Any restructuring agreement that may be reached would be implemented through a reorganization proceeding under Chapter 11 of the U.S. Bankruptcy Code.  None of JMC Selkirk, Inc., PentaGen Investors, L.P. or the Partnership are parties to such debt agreements and guaranteed equity commitments or participants in such discussions.  

Although NEG and its subsidiaries are continuing their efforts to maximize cash and reduce liabilities, such efforts are not expected to restore the financial condition of NEG and its subsidiaries.  Absent a negotiated agreement, the lenders may exercise their default remedies or force NEG and certain of its subsidiaries into an involuntary proceeding under the U.S. Bankruptcy Code.  Notwithstanding the status of current

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negotiations, NEG and certain of its subsidiaries also may elect to voluntarily seek protection under the U.S. Bankruptcy Code as early as the second quarter 2003.

NEG owns an indirect interest in the Partnership, and through its indirect, wholly owned subsidiaries, JMC Selkirk, Inc. and JMCS I Management, Inc., manages the Partnership.  The Partnership cannot be certain that an insolvency or bankruptcy involving NEG or any of its subsidiaries would not affect NEG’s ownership arrangements with respect to the Partnership or the ability of JMC Selkirk, Inc. or JMCS I Management, Inc. to manage the Partnership.  The Partnership Agreement provides certain management rights to RCM Selkirk GP, Inc. in the event that JMC Selkirk, Inc. were to be included in a bankruptcy involving NEG, including (i) the removal of JMC Selkirk, Inc. as the managing general partner, (ii) the appointment of itself as the successor managing general partner, and (iii) the termination of the administrative services agreement with JMCS I Management, Inc. and subsequent appointment of a RCM Selkirk GP, Inc. affiliate as the project management firm.  Enforcement of these rights by RCM Selkirk GP, Inc. could, however, be delayed or impeded as a result of any bankruptcy proceeding involving JMC Selkirk, Inc.  Moreover, the bankruptcy of any partner of the Partnership would be an event of default under the Partnership’s Credit Agreement.  Currently, the Partnership has contingent reimbursement obligations arising under letters of credit issued under this Credit Agreement in the amount of approximately $2.5 million, which the Partnership believes could be secured with cash collateral financed with cash flows from operations.  (See “Credit Agreement” below)

Results of Operations

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

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

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

Three Months Ended March 31, 2003 Compared to the Three Months Ended March 31, 2002

Overall Results

Net income was $15.0 million for the three months ended March 31, 2003, an increase of $5.6 million from the same period in the prior year.  This increase was primarily due to higher Unit 1 market energy prices and lower maintenance expenses.

The first quarter of 2003 included a net loss for the cumulative effect of a change in accounting principle of $53 thousand.  The cumulative effect was based on the Partnership’s adoption as of January 1, 2003, of Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Costs (see Note 2 to the Notes to Consolidated Financial Statements).

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

Operating Revenues

Operating revenues were $71.8 million for the three months ended March 31, 2003, an increase of $18.8 million from the same period in the prior year.  This increase was primarily due to higher electric and fuel revenues.  Unit 1 electric revenues increased by $6.0 million in the first quarter of 2003 primarily due to higher market energy prices.  Unit 2 electric revenues increased by $11.7 million in the first quarter of 2003 primarily due to higher fuel index pricing in the Con Edison contract price for delivered energy and higher volumes of delivered energy.  The higher volumes of delivered energy in the first quarter of 2003 primarily resulted from the performance of a four-week scheduled major maintenance outage on Unit 2 during the same period in the prior year.  Fuel revenues increased by $1.1 million in the first quarter of 2003 primarily due to the sale of natural gas under peak shaving arrangements, partially offset by lower volumes of natural gas available for resale.

Cost of Revenues

The cost of revenues was $47.9 million for the three months ended March 31, 2003, an increase of $13.6 million from the same period in the prior year.  This increase was primarily due to higher fuel and transmission costs; partially offset by lower other operating and maintenance costs.  Fuel and transmission costs increased by $17.4 million in the first quarter of 2003 primarily due to the higher price for natural gas under the firm gas supply contracts.  Other operating and maintenance costs decreased by $3.4 million in the first quarter of 2003 primarily due to the performance of a scheduled major maintenance outage on Unit 2 during the same period in the prior year.

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Liquidity and Capital Resources

Net cash provided by operating activities was $22.1 million for the three months ended March 31, 2003, an increase of $2.1 million from the same period in the prior year.  Net cash provided by operating activities primarily represents net income, adjusted by non-cash expenses and income, plus the net effect of changes within the Partnership’s operating assets and liability accounts.

Net cash used in investing activities was $0.2 million for the three months ended March 31, 2003, which was comparable to the same period in the prior year.  Net cash used in investing activities represents additions to plant and equipment.

Net cash used in financing activities was $23.7 million for the three months ended March 31, 2003, an increase of $1.1 million from the same period in the prior year.  This increase was primarily due to additional cash becoming available to deposit into the Principal Fund.  Pursuant to the Partnership’s Depositary and Disbursement Agreement, administered by Bankers Trust Company, as depositary agent, the Partnership is required to maintain certain Restricted Funds.  Net cash flows used in financing activities during the first quarter of 2003 and 2002 represent deposits of monies into the Interest Fund and Principal Fund.

Credit Ratings

On October 8, 2002, Moody’s Investor Services (“Moody’s”) stated that in conjunction with the downgrade of NEG, it had placed the Partnership’s debt under review for possible downgrade.  On October 15, 2002, Standard and Poor’s “(S&P”) stated that the recent downgrade of NEG will not have an affect on the rating of the Partnership’s debt at this time.  S&P’s rating of the Partnership’s debt is “BBB-”.  On November 5, 2002, Moody’s issued an opinion update changing the rating outlook of the Partnership’s debt to “under review for possible downgrade” from “stable” for the Partnership’s debt due in 2007 and “negative outlook” for the Partnership’s debt due in 2012.  Moody’s rating of the Partnership’s debt is “Baa3”.  A downgrade of the credit ratings of the Partnership's debt due in 2007 or 2012 by S&P or Moody's (or both) would not be an event of default under any of the Partnership's debt agreements and material project contracts or otherwise result in an adverse change to any material term of such agreements and contracts.

Credit Agreement

The Partnership has available for its use a credit agreement, as amended (“Credit Agreement”), with a maximum available credit of $7.5 million though August 8, 2003.  Outstanding balances bear interest at prime rate plus .375% per annum with principal and interest payable monthly in arrears.  The Credit Agreement is available to the Partnership for the purposes of meeting letters of credit requirements under various project contracts and for meeting working capital requirements.  Under the Credit Agreement, $2.5 million has been posted to meet letter of credit requirements and $5.0 million is available for working capital purposes.  As of March 31, 2003, there were no amounts drawn or balances outstanding under either the letters of credit or the working capital arrangement. 

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The Partnership does not expect the Credit Agreement to be renewed in August 2003 and is seeking to find a lender to replace the existing Credit Agreement.  If the Partnership is unable to replace the existing Credit Agreement, it may be required to secure its current letters of credit and any requests for additional assurances with cash collateral financed with cash flows from operations. The Partnership believes it will have sufficient cash flows from operations to secure its letters of credit and to meet its working capital requirements.

The Partnership believes, based on current conditions and circumstances, it will have sufficient cash flows from operations to fund existing debt obligations and operating costs during 2003.

Market Risk

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

Interest Rate Risk

Interest rate risk is the risk that changes in interest rates could adversely affect earnings or cashflows.  The Partnership's cash and restricted cash are sensitive to changes in interest rates.  Interest rate changes would result in a change in interest income due to the difference between the current interest rates on cash and restricted cash and the variable rate that these financial instruments may adjust to in the future.  Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cashflows as a result of assumed changes in market interest rates.  As of March 31, 2003, a 10% decrease in interest rates would be immaterial to the Partnership’s consolidated financial statements.

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

Foreign Currency Risk

Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies in relation to the U.S. dollar.  The Partnership uses currency swap agreements to partially hedge foreign currency exposure under fuel transportation agreements that are denominated in Canadian dollars.  In the event a counterparty fails to

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meet the terms of the currency swap agreements, the Partnership would be exposed to the risk that fluctuating currency exchange rates may adversely impact its financial results. 

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

Energy Commodity Price Risk

The Partnership seeks to reduce its exposure to market risk associated with energy commodities such as electric power and natural gas through the use of long-term purchase and sale contracts. As part of its fuel management activities, the Partnership also enters into agreements to resell its firm natural gas supply volumes, when it is feasible to do so, at favorable prices relative to the cost of contract volumes and the cost of substitute fuels.  To the extent the Partnership has open positions, it is exposed to the risk that fluctuating market prices may adversely impact its financial results.

Credit Risk

Credit risk is the risk of loss the Partnership would incur if counterparties fail to perform their contractual obligations (accounts receivable and due from affiliates).  The Partnership primarily conducts business with customers in the energy industry, such as investor-owned utilities, energy trading companies, financial institutions, gas production companies and gas transportation companies located in the United States and Canada.  This concentration of counterparties may impact the Partnership’s overall exposure to credit risk in that its counterparties may be similarly affected by changes in economic, regulatory or other conditions.  The Partnership mitigates potential credit losses in accordance with established credit approval practices and limits by dealing primarily with counterparties it considers to be of investment grade.

As of March 31, 2003, the Partnership’s credit risk is primarily concentrated with the following customers: Consolidated Edison Company of New York, Inc., Niagara Mohawk Power Corporation and the New York Independent System Operator, all of whom are considered to be of investment grade. 

Critical Accounting Policies

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

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The Partnership adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and 138 (collectively, SFAS No. 133), on January 1, 2001.  SFAS No. 133 requires the Partnership to recognize all derivatives, as defined in the statement, on the consolidated balance sheets at fair value.  Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income.  If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will offset the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recognized in other comprehensive income (loss) until the hedged items are recognized in earnings.  Derivatives are classified as asset for derivative contracts and liability for derivative contracts on the consolidated balance sheets (see Note 4 to the Consolidated Financial Statements - Accounting for Derivative Contracts).

Accounting Principles Issued But Not Yet Adopted

In January 2003, the Financial Accounting Standards Board  (“FASB”) issued Interpretation No. 46, Consolidation of Variable Interest Entities.  This interpretation applies to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date.  For variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003, application begins in the first fiscal year or interim period beginning after June 15, 2003.  The Partnership does not expect that implementation of this interpretation will have a significant impact on its consolidated financial statements.

In April 2003, the FASB issued Statement No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS No. 149”).  SFAS No. 149 amends and clarifies the accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133.  The amendments set forth in SFAS No. 149 require that contracts with comparable characteristics be accounted for similarly.  In particular, this statement clarifies under what circumstances a contract with an initial net investment meets the characteristics of a derivative according to SFAS No. 133 and when a derivative contains a financing component that warrants special reporting in the statement of cash flows. 

The requirements of SFAS 149 are effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003.   The provisions of the statement that relate to previous FASB guidance issued in the form of SFAS No. 133 Implementation Issues that have been effective for fiscal quarters that began prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates.  The Partnership is currently evaluating the impacts, if any, of SFAS 149 on its consolidated financial statements.

Legal Matters

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

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position or results of operations.  See Part I, Item 3 of the Partnership’s December 31, 2002 Annual Report on Form 10-K for further discussion of significant pending litigation.

Regulations and Environmental Matters

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

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ITEM 3.  QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

The Partnership is exposed to market risk from changes in interest rates, foreign currency exchange rates, energy commodity prices and credit risk, which could affect its future results of operations and financial condition.  The Partnership manages its exposure to these risks through its regular operating and financing activities.  (See “Market Risk”, included in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations above.)

ITEM 4.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Based on an evaluation of the Partnership’s disclosure controls and procedures conducted on May 2, 2003, the principal executive officers and principal financial officers of JMC Selkirk, Inc., as Managing General Partner of Selkirk Cogen Partners, L.P., and Selkirk Cogen Funding Corporation have concluded that such controls and procedures effectively ensure that information required to be disclosed by the Partnership in reports the Partnership files or submits under the Securities and Exchange Act of 1934 is recorded, processed, summarized, and reported, within the time periods specified in the Securities and Exchange Commission (“SEC”) rules and forms.  

Changes in Internal Controls

There were no significant changes in internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

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CERTIFICATION OF P. CHRISMAN IRIBE, PRINCIPAL EXECUTIVE OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES – OXLEY ACT OF 2002

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CERTIFICATION OF THOMAS E. LEGRO, PRINCIPAL FINANCIAL OFFICER, PURSUANT TO
SECTION 302 OF THE SARBANES – OXLEY ACT OF 2002

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CERTIFICATION OF P. CHRISMAN IRIBE, PRINCIPAL EXECUTIVE OFFICER, PURSUANT
TO SECTION 302 OF THE SARBANES – OXLEY ACT OF 2002

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CERTIFICATION OF THOMAS E. LEGRO, PRINCIPAL FINANCIAL OFFICER,

PURSUANT TO SECTION 302 OF THE SARBANES – OXLEY ACT OF 2002

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EXHIBIT INDEX

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