UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

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 September 30, 2003

Commission File Number 33-83618

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


Delaware (State or other jurisdiction of incorporation or organization)		51-0324332 (IRS Employer Identification No.)

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


Delaware (State or other jurisdiction of incorporation or organization)		51-0354675 (IRS Employer Identification No.)

7600 Wisconsin Avenue, 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 November 12, 2003, there were 10 shares of common stock of Selkirk Cogen Funding Corporation, $1 par value, outstanding.

EXPLANATORY NOTE

Selkirk Cogen Partners, L.P. hereby files its Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2003, originally filed by Selkirk Cogen Funding Corporation on November 13, 2003 (the “Form 10-Q”). Selkirk Cogen Partners, L.P. and Selkirk Cogen Funding Corporation intended to jointly file the Form 10-Q on November 13, 2003; however, when the Form 10-Q was delivered electronically to the SEC, the filing agent inadvertently omitted the filing codes of Selkirk Cogen Partners, L.P. As a result, only Selkirk Cogen Funding Corporation was listed on the SEC database as having filed the Form 10-Q. This report is being resubmitted to the SEC to reflect that the Form 10-Q has been filed by Selkirk Cogen Partners, L.P.

Except as described above, no changes have been made to the Form 10-Q. The Form 10-Q, continues to speak as to the date of the original filing, and disclosures contained therein have not been updated to reflect any subsequent events.

TABLE OF CONTENTS


		Page

	PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (unaudited)

	Consolidated Balance Sheets as of September 30, 2003 and December 31, 2002		1

	Consolidated Statements of Operations for the three and nine months ended September 30, 2003 and 2002		2

	Consolidated Statements of Cash Flows for the three and nine months ended September 30, 2003 and 2002		3

	Notes to Consolidated Financial Statements		4

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations

	Results of Operations		15

	Liquidity and Capital Resources		17

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		22

Item 4.	Controls and Procedures		22

	PART II. OTHER INFORMATION

Item 6.	Exhibits and Reports on Form 8-K		24

SIGNATURES			26

SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)


			September 30,			December 31,
			2003			2002

ASSETS
CURRENT ASSETS:
	Cash and cash equivalents		$	1,450		$	2,716
	Restricted funds			34,742			4,399
	Accounts receivable			22,393			20,116
	Due from affiliates			—			1,757
	Fuel inventory and supplies			6,038			6,436
	Other current assets			1,432			616

		Total current assets		66,055			36,040

PLANT AND EQUIPMENT:
	Plant and equipment, at cost			375,569			374,906
	Less: Accumulated depreciation			121,344			111,903

		Plant and equipment, net		254,225			263,003


LONG-TERM RESTRICTED FUNDS				30,872			34,600

DEFERRED FINANCING CHARGES, net of accumulated amortization of $10,759 and $9,979, respectively				5,532			6,312

TOTAL ASSETS			$	356,684		$	339,955

LIABILITIES AND PARTNERS’ DEFICITS

CURRENT LIABILITIES:
	Accounts payable		$	189		$	71
	Accrued bond interest payable			7,892			344
	Accrued fuel expenses			11,346			10,320
	Accrued property taxes			3,442			3,300
	Accrued operating and maintenance expenses			1,347			1,539
	Other accrued expenses			2,154			2,699
	Due to affiliates			2,183			2,454
	Current portion of long-term bonds			18,453			17,365
	Current portion of liability for derivative contracts			986			2,586

		Total current liabilities		47,992			40,678

LONG-TERM LIABILITIES:
	Deferred revenue			3,359			3,890
	Other long-term liabilities			7,218			6,691
	Long-term bonds — net of current portion			322,284			331,870
	Liability for derivative contracts — net of current portion			245			2,539

		Total liabilities		381,098			385,668


COMMITMENTS AND CONTINGENCIES

PARTNERS’ DEFICITS:
	General partners’ deficits			(236	)		(403	)
	Limited partners’ deficits			(22,947	)		(40,185	)
	Accumulated other comprehensive loss			(1,231	)		(5,125	)

		Total partners’ deficits		(24,414	)		(45,713	)

TOTAL LIABILITIES AND PARTNERS’ DEFICITS			$	356,684		$	339,955

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

SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands)
(Unaudited)


			Three Months Ended						Nine Months Ended

			September 30,			September 30,			September 30,			September 30,
			2003			2002			2003			2002

OPERATING REVENUES:
	Electric and steam		$	62,266		$	53,442		$	184,875		$	147,836
	Fuel revenues			2,310			4,834			13,884			16,819

		Total operating revenues		64,576			58,276			198,759			164,655

COST OF REVENUES:
	Fuel and transmission costs			35,579			31,078			112,286			83,017
	Unrealized loss on derivative contracts			—			—			—			446
	Other operating and maintenance			3,430			2,996			12,177			20,297
	Depreciation			3,148			3,140			9,427			9,400

		Total cost of revenues		42,157			37,214			133,890			113,160

GROSS PROFIT				22,419			21,062			64,869			51,495

OTHER OPERATING EXPENSES:
	Administrative services, affiliates			309			425			1,122			1,126
	Other general and administrative			913			811			2,227			2,272

		Total other operating expenses		1,222			1,236			3,349			3,398

OPERATING INCOME				21,197			19,826			61,520			48,097

INTEREST (INCOME) EXPENSE:
	Interest income			(123	)		(195	)		(455	)		(662	)
	Interest expense			7,812			8,156			23,806			24,758

		Total interest expense, net		7,689			7,961			23,351			24,096

INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE			$	13,508		$	11,865		$	38,169		$	24,001

CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE				—			—			(53	)		—

NET INCOME			$	13,508		$	11,865		$	38,116		$	24,001

NET INCOME ALLOCATION:
	General partners		$	136		$	118		$	382		$	240
	Limited partners			13,372			11,747			37,734			23,761

	TOTAL		$	13,508		$	11,865		$	38,116		$	24,001

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

SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)


					Three Months Ended						Nine Months Ended

					September 30,			September 30,			September 30,			September 30,
					2003			2002			2003			2002

CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income				$	13,508		$	11,865		$	38,116		$	24,001
	Adjustments to reconcile net income to net cash provided by operating activities:
		Cumulative effect of a change in accounting principle				—			—			53			—
		Depreciation, amortization and accretion				3,405			3,407			10,210			10,211
		Unrealized loss on derivative contracts				—			—			—			446
		Deferred revenue				(177	)		(176	)		(531	)		(530	)
		Loss on disposal of plant and equipment				—			—			—			481
		Increase (decrease) in cash resulting from a change in:
			Restricted funds			(184	)		1,652			(583	)		(1,750	)
			Accounts receivable			(1,184	)		106			(2,277	)		(247	)
			Due from affiliates			—			801			1,757			932
			Fuel inventory and supplies			(115	)		(646	)		398			3,661
			Other current assets			354			316			(816	)		(471	)
			Accounts payable			(429	)		(154	)		118			(1,515	)
			Accrued bond interest payable			7,556			7,888			7,548			7,882
			Accrued fuel expenses			(543	)		(89	)		1,026			723
			Accrued property taxes			42			44			142			948
			Accrued operating and maintenance expenses			(207	)		(2,280	)		(192	)		32
			Other accrued expenses			336			310			(545	)		(380	)
			Due to affiliates			131			(756	)		(271	)		(1,489	)
			Other long-term liabilities			730			730			440			541

				Net cash provided by operating activities		23,223			23,018			54,593			43,476


CASH FLOWS FROM INVESTING ACTIVITIES:
	Plant and equipment additions					(128	)		14			(618	)		(2,101	)

				Net cash provided by (used in) investing activities		(128	)		14			(618	)		(2,101	)


CASH FLOWS FROM FINANCING ACTIVITIES:
	Restricted funds					(26,032	)		(23,188	)		(26,032	)		(23,189	)
	Distributions to partners					(2,136	)		—			(20,711	)		(14,673	)
	Repayment of long-term debt					—			—			(8,498	)		(6,621	)

				Net cash used in financing activities		(28,168	)		(23,188	)		(55,241	)		(44,483	)


NET DECREASE IN CASH AND CASH EQUIVALENTS						(5,073	)		(156	)		(1,266	)		(3,108	)


CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD						6,523			1,594			2,716			4,546


CASH AND CASH EQUIVALENTS, END OF PERIOD					$	1,450		$	1,438		$	1,450		$	1,438

SUPPLEMENTAL CASH FLOW INFORMATION:
		Cash paid for interest			$	—		$	—		$	15,479		$	16,064

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

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 balance sheet at December 31, 2002, consolidated statements of operations for the three and nine months ended September 30, 2002 and consolidated statements of cash flows for the three and nine months ended September 30, 2002 to conform with the current period’s basis of presentation. Operating results for the three and nine months ended September 30, 2003 are not necessarily indicative of the results that may be expected for the year ending 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 revenues, 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 No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (“SFAS No. 133”).

The schedule below summarizes the activities affecting comprehensive income for the three and nine months ended September 30, 2003 and 2002 (in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,

	2003			2002			2003		2002

Net income	$	13,508		$	11,865		$	38,116	$	24,001

Net gain (loss) from current period hedging transactions in accordance with SFAS No. 133		(88	)		(1,204	)		2,870		244

Net reclassification to earnings		263			849			1,024		2,494

Comprehensive income	$	13,683		$	11,510		$	42,010	$	26,739

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 nine months ended September 30, 2002 would not have been material.

In June 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, which is effective for exit and disposal 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. Both SFAS No. 146 and Interpretation No. 45 were adopted on January 1, 2003 and did not have an impact on the Partnership’s 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 derivatives embedded in other contracts, and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies under what circumstances a contract with an initial net investment meets the characteristics of a derivative according to SFAS No. 133 and when a derivative contains a financing component that warrants special reporting in the statement of cash flows. The provisions of SFAS No. 149 that relate to SFAS No. 133 implementation issues that have been effective for periods that began prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates. This statement was adopted on July 1, 2003 and did not have an impact on the Partnership’s consolidated financial statements.

Accounting Principles Issued But Not Yet Adopted

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities (“FIN No. 46”), which expands upon existing accounting guidance addressing when a company should include in its financial statements the assets, liabilities, and activities of another entity or arrangement with which it is involved. A “variable interest entity” is an entity that does not have sufficient equity investment at risk to permit the entity to finance its activities without additional subordinated financial support from other parties or an entity where equity investors lack the essential characteristics of a controlling financial interest.

The consolidation requirements of FIN No. 46 apply immediately to variable interest entities created after January 31, 2003. There were no new variable interest entities created by the Partnership between February 1, 2003 and September 30, 2003. The consolidation requirements related to entities or arrangements existing before February 1, 2003 were originally effective July 1, 2003. However, due to implementation issues, the FASB deferred implementation until fourth quarter 2003. The Partnership is currently evaluating the impacts of FIN No. 46’s initial recognition, measurement, and disclosure provisions and does not expect that implementation of this interpretation will have a significant impact on its consolidated financial statements.

Note 3. Related Party Transactions

JMCS I Management, Inc., an affiliate of JMC Selkirk 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. at September 30, 2003 was approximately $268,000.

The Partnership purchases from and sells gas to affiliates of JMC Selkirk, Inc. As of March 18, 2003, PG&E Energy Trading, Canada Corporation (“ET Canada”) ceased to be a related party and, as of May 31, 2003, the Partnership ceased transactions with NEGT Energy Trading — Gas Corporation (“NEGT Energy Trading - Gas”, formerly PG&E Energy Trading – Gas Corporation). Gas purchases are recorded as fuel costs and sales of gas are recorded as fuel revenues in the accompanying consolidated statements of operations. There were no amounts due to/from ET Canada or NEGT Energy Trading – Gas at September 30, 2003. Amounts due to Pittsfield Generating Company, L.P. (“Pittsfield Generating”) and MASSPOWER at September 20, 2003 were approximately $21,000 and $1,338,000, respectively.

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


	Nine months ended September 30,

	2003		2002

NEGT Energy Trading – Gas	$	4,901	$	7,885
Pittsfield Generating		39		4
MASSPOWER		1,354		42

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


	Nine months ended September 30,

	2003		2002

NEGT Energy Trading – Gas	$	9,117	$	16,224
ET Canada		—		205
Pittsfield Generating		—		1
MASSPOWER		16		59

In May 1996, the Partnership entered into an enabling agreement with NEGT Energy Trading – Power, L.P., an affiliate of JMC Selkirk, Inc. (“NEGT Energy Trading — Power”, formerly PG&E Energy Trading – Power, L.P.), to purchase and sell electric capacity, electric energy, and other services. As of May 31, 2003, the Partnership ceased transactions with NEGT Energy Trading – Power. There were no sales of energy, capacity and other services pursuant to this enabling agreement for the nine months ended September 30, 2003, as compared to sales of approximately $1,563,000 for the same period in the prior year. There were no amounts due to or from NEGT Energy Trading – Power at September 30, 2003.

The Partnership has two agreements with Iroquois Gas Transmission System (“IGTS”), an affiliate of JMC Selkirk, Inc., to provide firm transportation of natural gas from Canada. Firm fuel transportation services for the nine months ended September 30, 2003 totaled approximately $5,275,000, compared to approximately $5,552,000 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 September 30, 2003 was approximately $556,000.

Note 4. Accounting For Derivative Contracts

Currency Exchange Contracts

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

The amount charged to fuel costs as a result of losses realized from these contracts for the nine months ended September 30, 2003 totaled approximately $1,024,000, compared to approximately $2,494,000 for the same period in the prior year. The Partnership expects that net derivative losses of approximately $986,000, included in accumulated other comprehensive loss as of September 30, 2003, will be charged to earnings within the next twelve months.

The schedule below summarizes the activities affecting accumulated other comprehensive loss from derivative contracts for the three and nine months ended September 30, 2003 and 2002 (in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2003			2002			2003			2002

Beginning accumulated other comprehensive loss at July 1 and January 1, respectively	$	(1,406	)	$	(5,708	)	$	(5,125	)	$	(8,801	)

Net gain (loss) from current period hedging transactions		(88	)		(1,204	)		2,870			244

Net reclassification to earnings		263			849			1,024			2,494

Ending accumulated other comprehensive loss	$	(1,231	)	$	(6,063	)	$	(1,231	)	$	(6,063	)

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 nine months ended September 30, 2002 was approximately $446,000. The Partnership had not entered into any peak shaving arrangements at September 30, 2003.

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 (including accounts receivable and due from affiliates). The Partnership primarily conducts business with customers in the energy industry, such as investor-owned utilities, energy trading companies, financial institutions, gas production 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 September 30, 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 which are considered to be of investment grade.

Note 6. Relationship with National Energy & Gas Transmission, Inc. (“NEGT”, formerly 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 NEGT. NEGT is an indirect subsidiary of PG&E Corporation.

On July 8, 2003, NEGT and certain subsidiaries voluntarily filed petitions for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (collectively, the “NEGT Bankruptcy”) in the Greenbelt Division of the United States Bankruptcy Court for the District of Maryland (the “Bankruptcy Court”). The subsidiaries that filed voluntarily petitions and were disclosed in previous filings as related parties of the Partnership with which it engaged in transactions are: NEGT Energy Trading-Power, L.P. (formerly PG&E Energy Trading-Power, L.P.) and NEGT Energy Trading–Gas Corporation (formerly PG&E Energy Trading-Gas Corporation).

Additionally, on July 8, 2003, NEGT filed its plan of reorganization (the “NEGT Plan”). The NEGT Plan anticipates that PG&E Corporation will have no equity interest in NEGT or any of its subsidiaries after the NEGT Plan is confirmed by the Bankruptcy Court and implemented. On July 7, 2003, the officers of PG&E Corporation who were serving on the Board of Directors of NEGT resigned their positions. On July 7 and July 8, 2003, the NEGT Board elected replacement directors who are not affiliated with PG&E Corporation. While continuing to maintain legal ownership, effective with this change in control of the Board and

the NEGT Bankruptcy, PG&E Corporation no longer retains significant influence over the ongoing operations of NEGT.

Neither the Partnership nor any of its NEGT affiliated partners, including JMC Selkirk, Inc. and PentaGen Investors, L.P., are parties to the NEGT Bankruptcy. The Managing General Partner believes that JMC Selkirk, Inc., PentaGen Investors, L.P. and the Partnership will not be substantively consolidated with NEGT in any bankruptcy proceeding involving NEGT. The Partnership believes that the NEGT Bankruptcy will not have a material adverse impact on its operations.

However, the Partnership cannot be certain that the NEGT Bankruptcy will not affect NEGT’s arrangements with respect to the Partnership or the ability of JMC Selkirk, 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 NEGT, or either JMC Selkirk, Inc. or JMCS I Management, Inc. were to be in material default of its obligations to the Partnership (following notice and a 120 day cure period), 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.

As a result of the sustained downturn in the power industry, NEGT and certain of its affiliates have experienced a financial downturn, which caused the major credit rating agencies to downgrade NEGT 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.

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

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

A downgrade of the credit ratings of the Partnership’s debt due in 2007 or 2012 by S&P or Moody’s (or both) would not be an event of default under any of the Partnership’s debt

agreements and material project contracts or otherwise result in an adverse change to any material term of such agreements and contracts.

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 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.

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 by the performance of equipment; levels of dispatch; the receipt of certain capacity and other fixed payments; electricity prices; natural gas resale prices; and fuel deliveries and prices.

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 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’s business may be affected by legislative or regulatory changes affecting the electric and natural gas industries in the United States, including the pace and extent of efforts to restructure the electric and natural gas industries; heightened regulatory and enforcement agency focus on the energy business with the potential for changes in industry regulations and

in the treatment of the Partnership by state and federal agencies; changes in or application of federal, state, and local laws and regulations to which the Partnership is subject; 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 units designed to operate independently for electrical generation, but thermally integrated for steam generation. Revenues are derived primarily from sales of electricity and, to a lesser extent, from sales of steam and natural gas. 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 nine months 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 nine months of 2002. The Partnership cannot 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. During the second quarter of 2003 scheduled non-major maintenance was performed on the Facility for a four-week period. The Facility has a one-week non-major maintenance outage scheduled for the fourth quarter of 2003.

Relationship with National Energy & Gas Transmission, Inc. (“NEGT”, formerly PG&E National Energy Group, Inc.)

On July 8, 2003, NEGT and certain subsidiaries voluntarily filed petitions for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (collectively, the “NEGT Bankruptcy”)

in the Greenbelt Division of the United States Bankruptcy Court for the District of Maryland (the “Bankruptcy Court”). The subsidiaries that filed voluntarily petitions and were disclosed in previous filings as related parties of the Partnership with which it engaged in transactions are: NEGT Energy Trading-Power, L.P. (“NEGT Energy Trading-Power”, formerly PG&E Energy Trading–Power, L.P) and NEGT Energy Trading – Gas Corporation (“NEGT Energy Trading-Gas”, formerly PG&E Energy Trading–Gas Corporation). As of May 31, 2003, the Partnership ceased transactions with NEGT Energy Trading–Power and NEGT Energy Trading–Gas. The Partnership believes there are sufficient counterparties available with which to undertake transactions in the electric and gas market and, therefore, the bankruptcy filings of NEGT Energy Trading–Power and NEGT Energy Trading–Gas will not have a material impact on the results of operations of the Partnership.

Additionally, on July 8, 2003, NEGT filed its plan of reorganization (“the NEGT Plan”). The NEGT Plan anticipates that PG&E Corporation will have no equity interest in NEGT or any of its subsidiaries after the NEGT Plan is confirmed by the Bankruptcy Court and implemented. On July 7, 2003 the officers of PG&E Corporation who were serving on the Board of Directors of NEGT resigned their positions. On July 7 and July 8, 2003, the NEGT Board elected replacement directors who are not affiliated with PG&E Corporation. While continuing to maintain legal ownership, effective with this change in control of the Board and the NEGT Bankruptcy, PG&E Corporation no longer retains significant influence over the ongoing operations of NEGT.

Results of Operations

The following tables set forth operating revenue and related data for the three and nine months ended September 30, 2003 and 2002 (dollars and volumes in millions).


		Three Months Ended September 30,

		2003					2002

		Volume			Dollars		Volume			Dollars

Dispatch factor:
	Unit 1		96.2	%				100.0	%
	Unit 2		98.2	%				100.0	%

Capacity factor:
	Unit 1		82.3	%				87.0	%
	Unit 2		97.1	%				98.4	%

Electric and steam revenues:
	Unit 1 (Kwh)		145.2		$	19.2		153.6		$	15.3
	Unit 2 (Kwh)		568.0			43.1		575.4			38.1
	Steam (lbs)		308.6			—		383.3			—

Total electric and steam revenues						62.3					53.4

Fuel revenues:
	Gas resales (mmbtu)		0.2			0.8		0.1			0.4
	Gas optimizations (mmbtu)		0.3			1.5		1.4			4.4
	Peak shaving arrangements (mmbtu)		—			—		—			—

Total fuel revenues						2.3					4.8

Total operating revenues					$	64.6				$	58.2


		Nine Months Ended September 30,

		2003					2002

		Volume			Dollars		Volume			Dollars

Dispatch factor:
	Unit 1		96.9	%				98.4	%
	Unit 2		90.9	%				85.2	%

Capacity factor:
	Unit 1		89.5	%				94.1	%
	Unit 2		88.8	%				78.0	%

Electric and steam revenues:
	Unit 1 (Kwh)		468.9		$	56.4		491.9		$	42.9
	Unit 2 (Kwh)		1,540.9			128.5		1,353.3			104.8
	Steam (lbs)		996.7			—		1,052.5			0.1

Total electric and steam revenues						184.9					147.8

Fuel revenues:
	Gas resales (mmbtu)		1.4			8.3		2.7			9.1
	Gas optimizations (mmbtu)		0.5			3.1		2.3			7.2
	Peak shaving arrangements (mmbtu)		0.2			2.5		—			0.5

Total fuel revenues						13.9					16.8

Total operating revenues					$	198.8				$	164.6

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 September 30, 2003 Compared to the Three Months Ended September 30, 2002

Overall Results

Net income was $13.5 million for the three months ended September 30, 2003, an increase of $1.6 million from the same period in the prior year. This increase was primarily due to higher Unit 1 electric revenues.

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

Operating Revenues

Operating revenues were $64.6 million for the three months ended September 30, 2003, an increase of $6.4 million from the same period in the prior year. This increase was primarily due to higher electric revenues. Unit 1 electric revenues increased by $3.9 million in the third quarter of 2003 primarily due to higher fuel index pricing in the energy component of the Niagara Mohawk Power Corporation (“Niagara Mohawk”) monthly contract payment and higher market energy prices. Unit 2 electric revenues increased by $5.0 million in the third quarter of 2003 primarily due to higher fuel index pricing in the Consolidated Edison Company of New York, Inc. (“Con Edison”) contract price for delivered energy. Fuel revenues decreased by $2.5 million in the third quarter of 2003 primarily due to lower volumes of natural gas sold under Gas Optimizations.

Cost of Revenues

The cost of revenues was $42.2 million for the three months ended September 30, 2003, an increase of $4.9 million from the same period in the prior year. This increase was primarily due to higher fuel costs. Fuel and transmission costs increased by $4.5 million in the third quarter of 2003 primarily due to the higher price for natural gas under the firm gas supply contracts, partially offset by lower volumes of natural gas purchased under Gas Optimizations.

Nine Months Ended September 30, 2003 Compared to the Nine Months Ended September 30, 2002

Overall Results

Net income was $38.1 million for the nine months ended September 30, 2003, an increase of $14.1 million from the same period in the prior year. This increase was primarily due to higher Unit 1 electric revenues and lower maintenance expenses.

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

Operating Revenues

Operating revenues were $198.8 million for the nine months ended September 30, 2003, an increase of $34.2 million from the same period in the prior year. This increase was primarily due to higher electric revenues. Unit 1 electric revenues increased by $13.5 million in the first nine months of 2003 primarily due to higher fuel index pricing in the energy component of the Niagara Mohawk monthly contract payment and higher market energy prices. Unit 2 electric revenues increased by $23.7 million in the first nine months 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 nine months of 2003 primarily resulted from the higher availability of Unit 2. During the first nine months of 2003, a four-week scheduled maintenance outage was performed on Unit 2, as compared to the performance of a four-week and six-week scheduled maintenance outage on Unit 2 during the same period in the prior year.

Cost of Revenues

The cost of revenues was $133.9 million for the nine months ended September 30, 2003, an increase of $20.7 million from the same period in the prior year. This increase was primarily due to higher fuel costs, partially offset by lower maintenance costs. Fuel and transmission costs increased by $29.3 million in the first nine months of 2003 primarily due to the higher price for natural gas under the firm gas supply contracts. Other operating and maintenance costs decreased by $8.1 million in the first nine months of 2003 primarily due to differences in the scope of scheduled maintenance. During the first nine months of 2003, a non-major maintenance outage was performed on Unit 2, as compared to the performance of two major maintenance outages on Unit 2 during the same period in the prior year.

Liquidity and Capital Resources

Net cash provided by operating activities was $23.2 million for the three months ended September 30, 2003, an increase of $0.2 million from the same period in the prior year. Net cash provided by operating activities was $54.6 million for the nine months ended September 30, 2003, an increase of $11.1 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 $0.1 million for the three months ended September 30, 2003, an increase of $0.1 million from the same period in the prior year. Net cash used in investing activities was $0.6 million for the nine months ended September 30, 2003, a decrease of $1.5 million from 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 $28.2 million for the three months ended September 30, 2003, an increase of $5.0 million from the same period in the prior year. Net cash used in financing activities was $55.2 million for the nine months ended September 30, 2003, an increase of $10.8 million from the same period in the prior year. These increases were primarily due to additional cash becoming available to deposit into the Restricted Funds and distribute to partners. 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 nine months ended September 30, 2003 and 2002 primarily represent the deposit of monies into the Interest, Principal and Debt Service Reserve Funds, distributions to partners and the semi-annual payment of principal and interest on long-term debt.

Credit Ratings

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

Until August 8, 2003, the Partnership had available for its use a credit agreement, as amended (the “Old Credit Agreement”), with a maximum available credit of $7.5 million. On August 8, 2003, the Partnership entered into an amendment to replace the Old Credit Agreement that

substituted Citizens Bank of Massachusetts for the previous lender, letter of credit issuer and agent and provided for a maximum available credit (including both outstanding letters of credit and working capital loans) of $10.0 million (the “Amended Credit Agreement” and together with the Old Credit Agreement, the “Credit Agreement”). Outstanding balances of working capital loans under the Amended Credit Agreement bear interest at a Base Rate plus 0% per annum with principal and interest payable monthly in arrears. The Base Rate under the Amended Credit Agreement is the greater of (i) a rate equal to the sum of the Federal Funds rate plus 0.50%, and (ii) the Prime Rate publicly announced by Citizens Bank of Massachusetts. The Amended Credit Agreement is available to the Partnership for the purposes of meeting letter of credit requirements under various fuel–related contracts and for meeting working capital requirements.

Under the Old Credit Agreement, a $2.5 million letter of credit had been posted to meet security requirements under one of the Partnership’s natural gas transportation service contracts with TransCanada PipeLines Limited (the “Gas Transportation Contract”). On July 22, 2003, the Partnership substituted cash collateral to secure the obligations previously secured by the letter of credit, which was terminated. Following the effectiveness of the Amended Credit Agreement, the Partnership delivered a new $2.9 million letter of credit issued under the Amended Credit Agreement to TransCanada PipeLines Limited as collateral to secure its obligations under the Gas Transportation Contract, and TransCanada PipeLines Limited returned the cash collateral deposit to the Partnership. As of September 30, 2003, there were no amounts drawn under such letter of credit and no balances outstanding under the working capital arrangement.

The Partnership believes, based on current conditions and circumstances, that 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 cash flow. 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 cash flows. 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 cash flows as a result of assumed changes in market interest rates. As of September 30, 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 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 September 30, 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.

Significant Commitments

There have been no new significant contractual obligations or commercial commitments since December 31, 2002.

Critical Accounting Policies

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

The Partnership adopted on January 1, 2001 Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (“SFAS No. 133”). SFAS No. 133 requires the Partnership to recognize all derivatives, as defined in the statement, on the consolidated balance sheets at fair value. Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will offset the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recognized in other comprehensive income (loss) until the hedged items are recognized in earnings. Derivatives are classified as assets for derivative contracts and liabilities 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 (“FIN No. 46”), which expands upon existing accounting guidance addressing when a company should include in its financial statements the assets, liabilities, and activities of another entity or arrangement with which it is involved. A “variable interest entity” is an entity that does not have sufficient equity investment at risk to permit the entity to finance its activities without additional subordinated financial support from other parties or an entity where equity investors lack the essential characteristics of a controlling financial interest.

The consolidation requirements of FIN No. 46 apply immediately to variable interest entities created after January 31, 2003. There were no new variable interest entities created by the Partnership between February 1, 2003 and September 30, 2003. The consolidation requirements related to entities or arrangements existing before February 1, 2003 were originally effective July 1, 2003. However, due to implementation issues, the FASB deferred implementation until the fourth quarter 2003. The Partnership is currently evaluating the

impacts of FIN No. 46’s initial recognition, measurement, and disclosure provisions and does not expect that implementation of this interpretation will have a significant impact 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 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

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 as of September 30, 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 factors that could significantly affect these controls subsequent to the date of the evaluation.

PART II. OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(A) Exhibits


Exhibit No.		Description of Exhibit

31.1		Certification of Principal Executive Officer of JMC Selkirk, Inc., as Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to Section 302 of the Sarbanes — Oxley Act of 2002 dated November 13, 2003

31.2		Certification of Principal Financial Officer of JMC Selkirk, Inc., as Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to Section 302 of the Sarbanes — Oxley Act of 2002 dated November 13, 2003

31.3		Certification of Principal Executive Officer of Selkirk Cogen Funding Corporation, pursuant to Section 302 of the Sarbanes — Oxley Act of 2002 dated November 13, 2003

31.4		Certification of Principal Financial Officer of Selkirk Cogen Funding Corporation, pursuant to Section 302 of the Sarbanes — Oxley Act of 2002 dated November 13, 2003

32.1		Certification of Principal Executive Officer of JMC Selkirk, Inc., as Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to Section 906 of the Sarbanes — Oxley Act of 2002 dated November 13, 2003

32.2		Certification of Principal Financial Officer of JMC Selkirk, Inc., as Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to Section 906 of the Sarbanes — Oxley Act of 2002 dated November 13, 2003

32.3		Certification of Principal Executive Officer of Selkirk Cogen Funding Corporation, pursuant to Section 906 of the Sarbanes — Oxley Act of 2002 dated November 13, 2003

32.4		Certification of Principal Financial Officer of Selkirk Cogen Funding Corporation, pursuant to Section 906 of the Sarbanes — Oxley Act of 2002 dated November 13, 2003

(B)

Reports on Form 8-K

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

Omitted from this Part II are items which are not applicable or to which the answer is negative for the periods covered.

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.

	By:	JMC SELKIRK, INC., Managing General Partner

Date: November 13, 2003	/s/ THOMAS E. LEGRO
	Name:	Thomas E. Legro
	Title:	Vice President, Controller, Chief Accounting Officer and Director



	SELKIRK COGEN FUNDING CORPORATION

Date: November 13, 2003	/s/ THOMAS E. LEGRO
	Name:	Thomas E. Legro
	Title:	Vice President, Controller, Chief Accounting Officer and Director

EXHIBIT INDEX


Exhibit No.		Description of Exhibit

31.1		Certification of Principal Executive Officer of JMC Selkirk, Inc., as Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to Section 302 of the Sarbanes – Oxley Act of 2002 dated November 13, 2003

31.2		Certification of Principal Financial Officer of JMC Selkirk, Inc., as Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to Section 302 of the Sarbanes – Oxley Act of 2002 dated November 13, 2003

31.3		Certification of Principal Executive Officer of Selkirk Cogen Funding Corporation, pursuant to Section 302 of the Sarbanes – Oxley Act of 2002 dated November 13, 2003

31.4		Certification of Principal Financial Officer of Selkirk Cogen Funding Corporation, pursuant to Section 302 of the Sarbanes – Oxley Act of 2002 dated November 13, 2003

32.1		Certification of Principal Executive Officer of JMC Selkirk, Inc., as Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to Section 906 of the Sarbanes – Oxley Act of 2002 dated November 13, 2003

32.2		Certification of Principal Financial Officer of JMC Selkirk, Inc., as Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to Section 906 of the Sarbanes – Oxley Act of 2002 dated November 13, 2003

32.3		Certification of Principal Executive Officer of Selkirk Cogen Funding Corporation, pursuant to Section 906 of the Sarbanes – Oxley Act of 2002 dated November 13, 2003

32.4		Certification of Principal Financial Officer of Selkirk Cogen Funding Corporation, pursuant to Section 906 of the Sarbanes – Oxley Act of 2002 dated November 13, 2003

SELKIRK COGEN PARTNERS LP 10-Q