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

TABLE OF CONTENTS


		Page

	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (unaudited)

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

	Consolidated Statements of Operations for the three and six months ended
	June 30, 2003 and 2002		2

	Consolidated Statements of Cash Flows for the three and six
	months ended June 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		24

Item 4.	Controls and Procedures		24

PART II. OTHER INFORMATION

Item 6.	Exhibits and Reports on Form 8-K		25


SIGNATURES			27

SELKIRK COGEN PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(In Thousands)

(Unaudited)


			June 30,			December 31,
			2003			2002

ASSETS
CURRENT ASSETS:
	Cash and cash equivalents		$	6,523		$	2,716
	Restricted funds			4,953			4,399
	Accounts receivable			21,209			20,116
	Due from affiliates			—			1,757
	Fuel inventory and supplies			5,923			6,436
	Other current assets			1,786			616

		Total current assets		40,394			36,040

PLANT AND EQUIPMENT:
	Plant and equipment, at cost			375,441			374,906
	Less: Accumulated depreciation			118,196			111,903

		Plant and equipment, net		257,245			263,003

LONG-TERM RESTRICTED FUNDS				34,445			34,600
DEFERRED FINANCING CHARGES, net of accumulated amortization of $10,503 and $9,979, respectively				5,788			6,312

TOTAL ASSETS			$	337,872		$	339,955

LIABILITIES AND PARTNERS’ DEFICITS
CURRENT LIABILITIES:
	Accounts payable		$	618		$	71
	Accrued bond interest payable			336			344
	Accrued fuel expenses			12,502			10,953
	Accrued property taxes			3,400			3,300
	Accrued operating and maintenance expenses			1,554			1,539
	Other accrued expenses			1,818			2,699
	Due to affiliates			1,439			1,821
	Current portion of long-term bonds			18,453			17,365
	Current portion of liability for derivative contracts			940			2,586

		Total current liabilities		41,060			40,678
LONG-TERM LIABILITIES:
	Deferred revenue			3,536			3,890
	Other long-term liabilities			6,487			6,691
	Long-term bonds — net of current portion			322,284			331,870
	Liability for derivative contracts — net of current portion			466			2,539

		Total liabilities		373,833			385,668

COMMITMENTS AND CONTINGENCIES
PARTNERS’ DEFICITS:
	General partners’ deficits			(348	)		(403	)
	Limited partners’ deficits			(34,207	)		(40,185	)
	Accumulated other comprehensive loss			(1,406	)		(5,125	)

		Total partners’ deficits		(35,961	)		(45,713	)

TOTAL LIABILITIES AND PARTNERS’ DEFICITS			$	337,872		$	339,955

The accompanying notes are an integral part of these consolidated financial statements.

SELKIRK COGEN PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands)

(Unaudited)


		Three Months Ended						Six Months Ended

		June 30,			June 30,			June 30,			June 30,
		2003			2002			2003			2002

OPERATING REVENUES:
	Electric and steam	$	55,445		$	44,931		$	122,609		$	94,394
	Fuel revenues		6,925			8,493			11,574			11,985

	Total operating revenues		62,370			53,424			134,183			106,379

COST OF REVENUES:
	Fuel and transmission costs		35,137			27,784			76,707			51,939
	Unrealized loss on derivative contracts		—			—			—			446
	Other operating and maintenance		5,601			10,770			8,747			17,301
	Depreciation		3,139			3,139			6,279			6,260

	Total cost of revenues		43,877			41,693			91,733			75,946

GROSS PROFIT			18,493			11,731			42,450			30,433

OTHER OPERATING EXPENSES:
	Administrative services, affiliates		395			187			813			701
	Other general and administrative		681			804			1,314			1,461

	Total other operating expenses		1,076			991			2,127			2,162

OPERATING INCOME			17,417			10,740			40,323			28,271

INTEREST (INCOME) EXPENSE:
	Interest income		(180	)		(260	)		(332	)		(467	)
	Interest expense		7,993			8,298			15,994			16,602

	Total interest expense, net		7,813			8,038			15,662			16,135

INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		$	9,604		$	2,702		$	24,661		$	12,136
CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE			—			—			(53	)		—

NET INCOME		$	9,604		$	2,702		$	24,608		$	12,136

NET INCOME ALLOCATION:
	General partners	$	95		$	28		$	246		$	122
	Limited partners		9,509			2,674			24,362			12,014

	TOTAL	$	9,604		$	2,702		$	24,608		$	12,136

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						Six Months Ended

					June 30,			June 30,			June 30,			June 30,
					2003			2002			2003			2002

CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income				$	9,604		$	2,702		$	24,608		$	12,136
	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			3,402			3,411			6,805			6,804
			Unrealized loss on derivative contracts			—			—			—			446
			Deferred revenue			(177	)		(177	)		(354	)		(354	)
			Loss on disposal of plant and equipment			—			481			—			481
			Increase (decrease) in cash resulting from a change in:
				Restricted funds		(1,138	)		(1,321	)		(399	)		(3,402	)
				Accounts receivable		6,765			(597	)		(1,093	)		(353	)
				Due from affiliates		195			(604	)		1,757			131
				Fuel inventory and supplies		569			2,585			513			4,307
				Other current assets		(1,348	)		(889	)		(1,170	)		(787	)
				Accounts payable		442			187			547			(1,361	)
				Accrued bond interest payable		(7,747	)		(8,038	)		(8	)		(6	)
				Accrued fuel expenses		(3,035	)		646			1,549			978
				Accrued property taxes		—			—			100			904
				Accrued operating and maintenance expenses		483			1,366			15			2,312
				Other accrued expenses		339			(354	)		(881	)		(690	)
				Due to affiliates		185			312			(382	)		(899	)
				Other long-term liabilities		730			730			(290	)		(189	)

				Net cash provided by operating activities		9,269			440			31,370			20,458

CASH FLOWS FROM INVESTING ACTIVITIES:
	Plant and equipment additions					(333	)		(1,949	)		(490	)		(2,115	)

				Net cash used in investing activities		(333	)		(1,949	)		(490	)		(2,115	)

CASH FLOWS FROM FINANCING ACTIVITIES:
	Restricted funds					23,690			22,597			—			(1	)
	Distributions to partners					(18,575	)		(14,673	)		(18,575	)		(14,673	)
	Repayment of long-term debt					(8,498	)		(6,621	)		(8,498	)		(6,621	)

				Net cash provided by (used in) financing activities		(3,383	)		1,303			(27,073	)		(21,295	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS						5,553			(206	)		3,807			(2,952	)

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD						970			1,800			2,716			4,546

CASH AND CASH EQUIVALENTS, END OF PERIOD					$	6,523		$	1,594		$	6,523		$	1,594

SUPPLEMENTAL CASH FLOW INFORMATION:
		Cash paid for interest			$	15,479		$	16,064		$	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 statement of operations for the three and six months ended June 30, 2002 to conform with the current period’s basis of presentation. Operating results for the three and six months ended June 30, 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”).

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,

	2003		2002		2003		2002

Net income	$	9,604	$	2,702	$	24,608	$	12,136
Net gain from current period hedging transactions in accordance with SFAS No. 133		1,600		1,401		2,958		1,448
Net reclassification to earnings		274		773		761		1,645

Comprehensive income	$	11,478	$	4,876	$	28,327	$	15,229

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 six months ended June 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.

Accounting Principles Issued But Not Yet Adopted

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities (“FIN 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.

Until the issuance of FIN 46, a company generally included another entity in its consolidated financial statements only if it controlled the entity through voting interests. FIN 46 changes that by requiring a variable interest entity to be consolidated by a company if that company is subject to a majority of the risk of loss from the variable interest entity’s activities or entitled to receive a majority of the entity’s residual returns, or both. A company that consolidates a variable interest entity is now referred to as the “primary beneficiary” of that entity. FIN 46 requires disclosures of variable interest entities that the company is not required to consolidate but in which it has a significant variable interest.

The consolidation requirements of FIN 46 apply immediately to variable interest entities created after January 31, 2003. There were no new variable interest entities created by the Partnership between February 1, 2003 and June 30, 2003. The consolidation requirements are applicable to the Partnership in the third quarter 2003. The Partnership is currently evaluating the impacts of Interpretation 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.

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.

The requirements of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The Partnership is currently evaluating the impacts, if any, of SFAS No. 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. at June 30, 2003, was approximately $1,439,000.

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. There were no amounts due to/from these affiliates at June 30, 2003. As of March 18, 2003, PG&E Energy Trading–Canada is no longer a related party. As of May 31, 2003, the Partnership ceased transactions with PG&E Energy Trading–Gas.

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


	Six months ended June 30,

	2003		2002

PG&E Energy Trading – Gas	$	4,901	$	3,464
MASSPOWER		—		42

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


	Six months ended June 30,

	2003		2002

PG&E Energy Trading – Gas	$	9,117	$	11,475
PG&E Energy Trading – Canada		—		126
Pittsfield Generating		—		1
MASSPOWER		—		59

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 six months ended June 30, 2003, compared to approximately $1,401,000 for the same period in the prior year. There was no amount due from PG&E Energy Trading–Power at June 30, 2003. As of May 31, 2003, the Partnership ceased transactions with PG&E Energy Trading–Power.

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 six months ended June 30, 2003 totaled approximately $3,547,000, compared to approximately $3,681,000 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 June 30, 2003, was approximately $613,000.

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).

The amount charged to fuel costs as a result of losses realized from these contracts for the six months ended June 30, 2003 totaled approximately $761,000, compared to approximately $1,645,000 for the same period in the prior year. The Partnership expects that net derivative losses of approximately $940,000, included in accumulated other comprehensive loss as of June 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 six months ended June 30, 2003 and 2002 (in thousands):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2003			2002			2003			2002

Beginning accumulated other comprehensive loss at April 1 and January 1, respectively	$	(3,280	)	$	(7,882	)	$	(5,125	)	$	(8,801	)
Net gain (loss) from current period hedging transactions		1,600			1,401			2,958			1,448
Net reclassification to earnings		274			773			761			1,645

Ending accumulated other comprehensive loss	$	(1,406	)	$	(5,708	)	$	(1,406	)	$	(5,708	)

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 six months ended June 30, 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 (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 June 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 whom are considered to be of investment grade.

Note 6. Relationship with 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 subsidiary of PG&E Corporation.

On July 8, 2003, NEG and certain subsidiaries voluntarily filed petitions for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (collectively, the “NEG 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: PG&E Energy Trading-Power, L.P. and PG&E Energy Trading – Gas Corporation.

Additionally, on July 8, 2003, NEG filed its plan of reorganization (the “NEG Plan”). The NEG Plan anticipates that PG&E Corporation will have no equity interest in NEG or any of its subsidiaries after the NEG 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 NEG resigned their positions. On July 7 and July 8, 2003, the NEG 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 NEG Bankruptcy, PG&E Corporation no longer retains significant influence over the ongoing operations of NEG.

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

However, the Partnership cannot be certain that the NEG Bankruptcy will 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, 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, 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.

As previously reported 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. Moody’s stated that its rating confirmation reflects its assessment that the credit deterioration of several companies that have an ownership interest in the Partnership, including subsidiaries of PG&E National Energy Group, Inc. (Ca senior unsecured), Aquila Inc. (Caa1 senior unsecured), and Cogentrix (B1 senior unsecured), has not significantly diminished Selkirk Cogen Funding Corporation’s ability to meet its obligations.

rating on Selkirk Cogen Funding Corporation is not affected by the ratings action on NEG. S&P’s rating of the Partnership’s debt 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 six 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 six 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 first six months of 2003, four weeks of scheduled non-major maintenance was performed on the Facility. The Facility has a one-week non-major maintenance outage scheduled for the remainder of 2003.

Relationship with PG&E National Energy Group, Inc. (“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 subsidiary of PG&E Corporation.

On July 8, 2003, NEG and certain subsidiaries voluntarily filed petitions for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (collectively, the “NEG 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: PG&E Energy Trading-Power, L.P. (“PG&E Energy Trading–Power”) and PG&E Energy Trading – Gas Corporation (“PG&E Energy Trading–Gas”). As of May 31, 2003, the Partnership ceased transactions with PG&E Energy Trading–Power and PG&E 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 PG&E Energy Trading–Power and PG&E Energy Trading–Gas will not have a material impact on the results of operations of the Partnership.

Additionally, on July 8, 2003, NEG filed its plan of reorganization (“the NEG Plan”). The NEG Plan anticipates that PG&E Corporation will have no equity interest in NEG or any of its subsidiaries after the NEG 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 NEG resigned their positions. On July 7 and July 8, 2003, the NEG 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 NEG Bankruptcy, PG&E Corporation no longer retains significant influence over the ongoing operations of NEG.

Results of Operations

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


		Three Months Ended June 30,

		2003						2002

		Volume			Dollars			Volume			Dollars

Dispatch factor:
	Unit 1		98.1	%					95.2	%
	Unit 2		74.4	%					57.8	%
Capacity factor:
	Unit 1		94.4	%					91.7	%
	Unit 2		70.9	%					56.2	%
Electric and steam revenues:
	Unit 1 (Kwh)		164.8		$	16.3			159.9		$	12.7
	Unit 2 (Kwh)		410.5			39.3			325.0			32.3
	Steam (lbs)		337.4			(0.1	)		301.5			(0.1	)

Total electric and steam revenues						55.5						44.9
Fuel revenues:
	Gas resales (mmbtu)		1.1			6.9			2.0			7.2
	Gas optimizations (mmbtu)		—			—			0.3			1.3
	Peak shaving arrangements (mmbtu)		—			—			—			—

Total fuel revenues						6.9						8.5

Total operating revenues					$	62.4					$	53.4


		Six Months Ended June 30,

		2003					2002

		Volume			Dollars		Volume			Dollars

Dispatch factor:
	Unit 1		97.3	%				97.6	%
	Unit 2		87.1	%				77.7	%
Capacity factor:
	Unit 1		93.2	%				97.8	%
	Unit 2		84.5	%				67.6	%
Electric and steam revenues:
	Unit 1 (Kwh)		323.7		$	37.2		338.4		$	27.6
	Unit 2 (Kwh)		972.9			85.4		777.9			66.8
	Steam (lbs)		688.1			—		669.2			—

Total electric and steam revenues						122.6					94.4
Fuel revenues:
	Gas resales (mmbtu)		1.2			7.5		2.6			8.7
	Gas optimizations (mmbtu)		0.2			1.6		0.9			2.8
	Peak shaving arrangements (mmbtu)		0.2			2.5		—			0.5

Total fuel revenues						11.6					12.0

Total operating revenues					$	134.2				$	106.4

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

Overall Results

Net income was $9.6 million for the three months ended June 30, 2003, an increase of $6.9 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 $62.4 million for the three months ended June 30, 2003, an increase of $9.0 million from the same period in the prior year. This increase was primarily due to higher electric revenues. Unit 1 electric revenues increased by $3.6 million in the second 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 $7.0 million in the second 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 and higher volumes of delivered energy. The higher volumes of delivered energy in the second quarter of 2003 primarily resulted from the higher availability of Unit 2. During the second quarter of 2003, a four-week scheduled maintenance outage was performed on Unit 2, as compared to the performance of a six-week scheduled maintenance outage on Unit 2 during the same period in the prior year. Fuel revenues decreased by $1.6 million in the second quarter of 2003 primarily due to no sales of natural gas under gas optimizations.

Cost of Revenues

The cost of revenues was $43.9 million for the three months ended June 30, 2003, an increase of $2.2 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 $7.4 million in the second 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 $5.2 million in the second quarter of 2003 primarily due to differences in the scope of scheduled maintenance. During the second quarter of 2003, a non-major

maintenance outage was performed on Unit 2, as compared to the performance of a major maintenance outage on Unit 2 during the same period in the prior year.

Six Months Ended June 30, 2003 Compared to the Six Months Ended June 30, 2002

Overall Results

Net income was $24.6 million for the six months ended June 30, 2003, an increase of $12.5 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 $134.2 million for the six months ended June 30, 2003, an increase of $27.8 million from the same period in the prior year. This increase was primarily due to higher electric revenues. Unit 1 electric revenues increased by $9.6 million in the first six 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 $18.6 million in the first six 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 six months of 2003 primarily resulted from the higher availability of Unit 2. During the first six 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 $91.7 million for the six months ended June 30, 2003, an increase of $15.8 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 $24.8 million in the first six 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 $8.5 million in the first six months of 2003 primarily due to differences in the scope of scheduled maintenance. During the first six 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 $9.3 million for the three months ended June 30, 2003, an increase of $8.8 million from the same period in the prior year. Net cash provided by operating activities was $31.4 million for the six months ended June 30, 2003, an increase of $10.9 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 $0.3 million for the three months ended June 30, 2003, a decrease of $1.6 million from the same period in the prior year. Net cash used in investing activities was $0.5 million for the six months ended June 30, 2003, a decrease of $1.6 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 $3.4 million for the three months ended June 30, 2003, an increase of $4.7 million from the same period in the prior year. Net cash used in financing activities was $27.1 million for the six months ended June 30, 2003, an increase of $5.8 million from the same period in the prior year. These increases were primarily due to additional cash becoming available to distribute to partners and higher principal payments on long-term debt. 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 three and six months ended June 30, 2003 and 2002 primarily represent distributions to partners and the semi-annual payment of principal and interest on long-term debt.

Credit Ratings

As previously reported 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 NEG’s subsidiaries. S&P stated these ratings actions follow the NEG Bankruptcy. S&P further stated that the rating on Selkirk Cogen Funding Corporation is not affected by the ratings action on NEG because this project financing is structured as a bankruptcy-remote entity and is not 100% owned by NEG. Therefore, the incentive to consolidate it in a bankruptcy of NEG is low. S&P’s rating of the Partnership’s debt 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.

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. 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”), and $5.0 million was available for working capital purposes. As of June 30, 2003, there were no amounts drawn under such letter of credit and no balances outstanding under the working capital arrangement. On July 22, 2003, the Partnership substituted cash collateral to secure the obligations previously secured by the letter of credit, which was terminated.

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. The Partnership is in the process of replacing the cash collateral previously posted on July 22, 2003 to secure its obligations under the Gas Transportation Contract with a letter of credit to be issued under the Amended Credit Agreement.

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 June 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 June 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 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 (“FIN 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.

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

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 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 July 16, 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.

PART II. OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(A) Exhibits


Exhibit No.		Description of Exhibit

10.1		Amendment No. 6 to Credit Agreement, dated August 8, 2003, between the Partnership and Citizens Bank of Massachusetts

10.4		Letter Agreement regarding O&M Agreement, dated June 27, 2003, between the Partnership and GE International, Inc.

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 August 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 August 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 August 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 August 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 August 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 August 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 August 13, 2003


Exhibit No.		Description of Exhibit

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

(B) Reports on Form 8-K

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

			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: August 13, 2003	/s/ THOMAS E. LEGRO

	Name:	Thomas E. Legro
	Title:	Vice President, Controller, Chief Accounting Officer and Director

	SELKIRK COGEN FUNDING CORPORATION

Date: August 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

10.1		Amendment No. 6 to Credit Agreement, dated August 8, 2003, between the Partnership and Citizens Bank of Massachusetts

10.4		Letter Agreement regarding O&M Agreement, dated June 27, 2003, between the Partnership and GE International, Inc.

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 August 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 August 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 August 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 August 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 August 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 August 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 August 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 August 13, 2003

SELKIRK COGEN FUNDING CORP 10-Q