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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 1934For 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.



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TABLE OF CONTENTS

PagePART I. FINANCIAL INFORMATIONItem 1.
    
    Financial Statements (unaudited)Consolidated Balance Sheets as of June 30, 2003and December 31, 2002
    
    
    1Consolidated Statements of Operations for the three and six months endedJune 30, 2003 and 2002
    
    
    2Consolidated Statements of Cash Flows for the three and sixmonths ended June 30, 2003 and 2002
    
    
    3Notes to Consolidated Financial Statements
    
    
    4Item 2.
    
    Managements Discussion and Analysis of Financial Conditionand Results of OperationsResults of Operations
    
    
    15Liquidity and Capital Resources
    
    
    17Item 3.
    
    Quantitative and Qualitative Disclosures About Market Risk
    
    
    24Item 4.
    
    Controls and Procedures
    
    
    24PART II. OTHER INFORMATIONItem 6.
    
    Exhibits and Reports
on Form 8-K
    
    
    25SIGNATURES
    
    
    27




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SELKIRK COGEN PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS


(In Thousands)


(Unaudited)


June 30,
      
      December 31,2003
      
      2002ASSETSCURRENT
          ASSETS:Cash
          and cash equivalents
      
      $
      6,523
      
      
      $
      2,716Restricted
          funds
      
      
      4,953
      
      
      
      4,399Accounts
          receivable
      
      
      21,209
      
      
      
      20,116Due
          from affiliates
      
      
      
      
      
      
      1,757Fuel
          inventory and supplies
      
      
      5,923
      
      
      
      6,436Other
          current assets
      
      
      1,786
      
      
      
      616Total
          current assets
      
      
      40,394
      
      
      
      36,040PLANT
          AND EQUIPMENT:Plant
          and equipment, at cost
      
      
      375,441
      
      
      
      374,906Less:
          Accumulated depreciation
      
      
      118,196
      
      
      
      111,903Plant
          and equipment, net
      
      
      257,245
      
      
      
      263,003LONG-TERM
          RESTRICTED FUNDS
      
      
      34,445
      
      
      
      34,600DEFERRED
          FINANCING CHARGES, net of accumulated amortization of $10,503 and $9,979,
          respectively
      
      
      5,788
      
      
      
      6,312TOTAL
          ASSETS
      
      $
      337,872
      
      
      $
      339,955LIABILITIES
          AND PARTNERS DEFICITSCURRENT
          LIABILITIES:Accounts
          payable
      
      $
      618
      
      
      $
      71Accrued
          bond interest payable
      
      
      336
      
      
      
      344Accrued
          fuel expenses
      
      
      12,502
      
      
      
      10,953Accrued
          property taxes
      
      
      3,400
      
      
      
      3,300Accrued
          operating and maintenance expenses
      
      
      1,554
      
      
      
      1,539Other
          accrued expenses
      
      
      1,818
      
      
      
      2,699Due
          to affiliates
      
      
      1,439
      
      
      
      1,821Current
          portion of long-term bonds
      
      
      18,453
      
      
      
      17,365Current
          portion of liability for derivative contracts
      
      
      940
      
      
      
      2,586Total
          current liabilities
      
      
      41,060
      
      
      
      40,678LONG-TERM
          LIABILITIES:Deferred
          revenue
      
      
      3,536
      
      
      
      3,890Other
          long-term liabilities
      
      
      6,487
      
      
      
      6,691Long-term
          bonds  net of current portion
      
      
      322,284
      
      
      
      331,870Liability
          for derivative contracts  net of current portion
      
      
      466
      
      
      
      2,539Total
          liabilities
      
      
      373,833
      
      
      
      385,668COMMITMENTS
          AND CONTINGENCIESPARTNERS
          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.

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SELKIRK COGEN PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS


(In Thousands)


(Unaudited)


Three Months Ended
    
    Six Months EndedJune 30,
    
    June 30,
    
    June 30,
    
    June 30,2003
    
    2002
    
    2003
    
    2002OPERATING REVENUES:Electric and steam
    
    $
    55,445
    
    
    $
    44,931
    
    
    $
    122,609
    
    
    $
    94,394Fuel revenues
    
    
    6,925
    
    
    
    8,493
    
    
    
    11,574
    
    
    
    11,985Total operating revenues
    
    
    62,370
    
    
    
    53,424
    
    
    
    134,183
    
    
    
    106,379COST OF REVENUES:Fuel and transmission costs
    
    
    35,137
    
    
    
    27,784
    
    
    
    76,707
    
    
    
    51,939Unrealized loss on derivative contracts
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    446Other operating and maintenance
    
    
    5,601
    
    
    
    10,770
    
    
    
    8,747
    
    
    
    17,301Depreciation
    
    
    3,139
    
    
    
    3,139
    
    
    
    6,279
    
    
    
    6,260Total cost of revenues
    
    
    43,877
    
    
    
    41,693
    
    
    
    91,733
    
    
    
    75,946GROSS PROFIT
    
    
    18,493
    
    
    
    11,731
    
    
    
    42,450
    
    
    
    30,433OTHER OPERATING EXPENSES:Administrative services, affiliates
    
    
    395
    
    
    
    187
    
    
    
    813
    
    
    
    701Other general and administrative
    
    
    681
    
    
    
    804
    
    
    
    1,314
    
    
    
    1,461Total other operating expenses
    
    
    1,076
    
    
    
    991
    
    
    
    2,127
    
    
    
    2,162OPERATING INCOME
    
    
    17,417
    
    
    
    10,740
    
    
    
    40,323
    
    
    
    28,271INTEREST (INCOME) EXPENSE:Interest income
    
    
    (180
    )
    
    
    (260
    )
    
    
    (332
    )
    
    
    (467
    )Interest expense
    
    
    7,993
    
    
    
    8,298
    
    
    
    15,994
    
    
    
    16,602Total interest expense, net
    
    
    7,813
    
    
    
    8,038
    
    
    
    15,662
    
    
    
    16,135INCOME BEFORE CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE
    
    $
    9,604
    
    
    $
    2,702
    
    
    $
    24,661
    
    
    $
    12,136CUMULATIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE
    
    
    
    
    
    
    
    
    
    
    (53
    )
    
    
    NET INCOME
    
    $
    9,604
    
    
    $
    2,702
    
    
    $
    24,608
    
    
    $
    12,136NET INCOME ALLOCATION:General partners
    
    $
    95
    
    
    $
    28
    
    
    $
    246
    
    
    $
    122Limited partners
    
    
    9,509
    
    
    
    2,674
    
    
    
    24,362
    
    
    
    12,014TOTAL
    
    $
    9,604
    
    
    $
    2,702
    
    
    $
    24,608
    
    
    $
    12,136


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

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SELKIRK COGEN PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS


(In Thousands)


(Unaudited)


Three Months Ended
    
    Six Months EndedJune 30,
    
    June 30,
    
    June 30,
    
    June 30,2003
    
    2002
    
    2003
    
    2002CASH FLOWS FROM OPERATING ACTIVITIES:Net income
    
    $
    9,604
    
    
    $
    2,702
    
    
    $
    24,608
    
    
    $
    12,136Adjustments 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
    
    
    
    6,804Unrealized loss on derivative contracts
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    446Deferred revenue
    
    
    (177
    )
    
    
    (177
    )
    
    
    (354
    )
    
    
    (354
    )Loss on disposal of plant and equipment
    
    
    
    
    
    
    481
    
    
    
    
    
    
    
    481Increase (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
    
    
    
    131Fuel inventory and supplies
    
    
    569
    
    
    
    2,585
    
    
    
    513
    
    
    
    4,307Other 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
    
    
    
    978Accrued property taxes
    
    
    
    
    
    
    
    
    
    
    100
    
    
    
    904Accrued operating and maintenance expenses
    
    
    483
    
    
    
    1,366
    
    
    
    15
    
    
    
    2,312Other 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
    
    
    
    20,458CASH 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
    
    
    
    4,546CASH AND CASH EQUIVALENTS,
END OF PERIOD
    
    $
    6,523
    
    
    $
    1,594
    
    
    $
    6,523
    
    
    $
    1,594SUPPLEMENTAL 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.

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SELKIRK COGEN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Note 1. Basis of Presentation

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

The consolidated financial statements for the interim periods presented are
unaudited and have been prepared pursuant to the rules and regulations of the
Securities and Exchange Commission. Certain information and footnote
disclosures normally included in financial statements prepared in accordance
with accounting principles generally accepted in the United States have been
omitted pursuant to rules and regulations applicable to interim financial
statements. The information furnished in the consolidated financial statements
reflects all normal recurring adjustments, which, in the opinion of management,
are necessary for a fair presentation of such financial statements. Certain
reclassifications have been made to the consolidated statement of operations
for the three 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).

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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 EndedJune 30,
    
    June 30,2003
    
    2002
    
    2003
    
    2002Net income
    
    $
    9,604
    
    
    $
    2,702
    
    
    $
    24,608
    
    
    $
    12,136Net gain from current period
hedging transactions in accordance
with SFAS No. 133
    
    
    1,600
    
    
    
    1,401
    
    
    
    2,958
    
    
    
    1,448Net reclassification to earnings
    
    
    274
    
    
    
    773
    
    
    
    761
    
    
    
    1,645Comprehensive 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

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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.

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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
    
    2002PG&E Energy Trading  Gas
    
    $
    4,901
    
    
    $
    3,464MASSPOWER
    
    
    
    
    
    
    42


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

Six months ended June 30,2003
    
    2002PG&E Energy Trading  Gas
    
    $
    9,117
    
    
    $
    11,475PG&E Energy Trading  Canada
    
    
    
    
    
    
    126Pittsfield Generating
    
    
    
    
    
    
    1MASSPOWER
    
    
    
    
    
    
    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.

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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 EndedJune 30,
    
    June 30,2003
    
    2002
    
    2003
    
    2002Beginning 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
    
    
    
    1,448Net reclassification to earnings
    
    
    274
    
    
    
    773
    
    
    
    761
    
    
    
    1,645Ending accumulated other
comprehensive loss
    
    $
    (1,406
    )
    
    $
    (5,708
    )
    
    $
    (1,406
    )
    
    $
    (5,708
    )


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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

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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.

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

10



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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.

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

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

Cautionary Statement Regarding Forward-Looking Statements

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

Operational Risks

The Partnerships future results of operations and financial condition may be
affected 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

12



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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)

13



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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.

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. However, the Partnership believes that any contingent
reimbursement obligations arising under letters of credit issued under this
Credit Agreement could be secured with cash collateral financed with cash
flows from operations.

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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
    
    2002Volume
    
    Dollars
    
    Volume
    
    DollarsDispatch
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
    
    
    $
    12.7Unit 2 (Kwh)
    
    
    410.5
    
    
    
    39.3
    
    
    
    325.0
    
    
    
    32.3Steam (lbs)
    
    
    337.4
    
    
    
    (0.1
    )
    
    
    301.5
    
    
    
    (0.1
    )Total electric and steam
revenues
    
    
    
    
    
    
    55.5
    
    
    
    
    
    
    
    44.9Fuel
revenues:Gas resales (mmbtu)
    
    
    1.1
    
    
    
    6.9
    
    
    
    2.0
    
    
    
    7.2Gas optimizations (mmbtu)
    
    
    
    
    
    
    
    
    
    
    0.3
    
    
    
    1.3Peak shaving
arrangements (mmbtu)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total fuel revenues
    
    
    
    
    
    
    6.9
    
    
    
    
    
    
    
    8.5Total operating revenues
    
    
    
    
    
    $
    62.4
    
    
    
    
    
    
    $
    53.4


Six Months Ended June 30,2003
    
    2002Volume
    
    Dollars
    
    Volume
    
    DollarsDispatch
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
    
    
    $
    27.6Unit 2 (Kwh)
    
    
    972.9
    
    
    
    85.4
    
    
    
    777.9
    
    
    
    66.8Steam (lbs)
    
    
    688.1
    
    
    
    
    
    
    
    669.2
    
    
    
    Total electric and steam
revenues
    
    
    
    
    
    
    122.6
    
    
    
    
    
    
    
    94.4Fuel
revenues:Gas resales (mmbtu)
    
    
    1.2
    
    
    
    7.5
    
    
    
    2.6
    
    
    
    8.7Gas optimizations (mmbtu)
    
    
    0.2
    
    
    
    1.6
    
    
    
    0.9
    
    
    
    2.8Peak shaving
arrangements (mmbtu)
    
    
    0.2
    
    
    
    2.5
    
    
    
    
    
    
    
    0.5Total fuel revenues
    
    
    
    
    
    
    11.6
    
    
    
    
    
    
    
    12.0Total operating revenues
    
    
    
    
    
    $
    134.2
    
    
    
    
    
    
    $
    106.4


15



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

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

Three Months Ended 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

16



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##### 



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

17



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##### 



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 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.
Moodys stated that the Baa3 rating reflects consistently strong and
predictable operating performance. Moodys stated that its stable ratings
outlook reflects an expectation of continued predictable financial performance
over the near term.

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

18



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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.

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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

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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.

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.

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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.

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

22



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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.

23



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ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Based on an evaluation of the Partnerships disclosure controls and procedures
conducted on 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.

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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                                             

25



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|            |  |                                                                                                                                                                     
|----------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------
|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.

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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

27



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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