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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 1934
For the quarterly period ended September 30, 2003

Commission File Number 33-83618

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

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


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

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


7600 Wisconsin Avenue, Bethesda, Maryland 20814
(Address of principal executive offices, including zip code)

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

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

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

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

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



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TABLE OF CONTENTS

PagePART I.  FINANCIAL INFORMATIONItem 1.
    
    Financial Statements (unaudited)Consolidated Balance Sheets as of September 30, 2003  and December 31, 2002
    
    
    1Consolidated Statements of Operations for the three and nine months ended  September 30, 2003 and 2002
    
    
    2Consolidated Statements of Cash Flows for the three and nine  months ended September 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
    
    
    22Item 4.
    
    Controls and Procedures
    
    
    22PART II.  OTHER INFORMATIONItem 6.
    
    Exhibits and Reports on Form 8-K
    
    
    24SIGNATURES
    
    
    
    
    
    
    26


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

September 30,
    
    
    December 31,2003
    
    
    2002ASSETSCURRENT ASSETS:Cash and cash equivalents
    
    $
    1,450
    
    
    $
    2,716Restricted funds
    
    
    34,742
    
    
    
    4,399Accounts receivable
    
    
    22,393
    
    
    
    20,116Due from affiliates
    
    
    
    
    
    
    1,757Fuel inventory and supplies
    
    
    6,038
    
    
    
    6,436Other current assets
    
    
    1,432
    
    
    
    616Total current assets
    
    
    66,055
    
    
    
    36,040PLANT AND EQUIPMENT:Plant and equipment, at cost
    
    
    375,569
    
    
    
    374,906Less: Accumulated depreciation
    
    
    121,344
    
    
    
    111,903Plant and equipment, net
    
    
    254,225
    
    
    
    263,003LONG-TERM RESTRICTED FUNDS
    
    
    30,872
    
    
    
    34,600DEFERRED FINANCING CHARGES, net of accumulated
amortization of $10,759 and $9,979, respectively
    
    
    5,532
    
    
    
    6,312TOTAL ASSETS
    
    $
    356,684
    
    
    $
    339,955LIABILITIES AND PARTNERS DEFICITSCURRENT LIABILITIES:Accounts payable
    
    $
    189
    
    
    $
    71Accrued bond interest payable
    
    
    7,892
    
    
    
    344Accrued fuel expenses
    
    
    11,346
    
    
    
    10,320Accrued property taxes
    
    
    3,442
    
    
    
    3,300Accrued operating and maintenance expenses
    
    
    1,347
    
    
    
    1,539Other accrued expenses
    
    
    2,154
    
    
    
    2,699Due to affiliates
    
    
    2,183
    
    
    
    2,454Current portion of long-term bonds
    
    
    18,453
    
    
    
    17,365Current portion of liability for derivative contracts
    
    
    986
    
    
    
    2,586Total current liabilities
    
    
    47,992
    
    
    
    40,678LONG-TERM LIABILITIES:Deferred revenue
    
    
    3,359
    
    
    
    3,890Other long-term liabilities
    
    
    7,218
    
    
    
    6,691Long-term bonds  net of current portion
    
    
    322,284
    
    
    
    331,870Liability for derivative contracts  net of current portion
    
    
    245
    
    
    
    2,539Total liabilities
    
    
    381,098
    
    
    
    385,668COMMITMENTS AND CONTINGENCIESPARTNERS DEFICITS:General partners deficits
    
    
    (236
    )
    
    
    (403
    )Limited partners deficits
    
    
    (22,947
    )
    
    
    (40,185
    )Accumulated other comprehensive loss
    
    
    (1,231
    )
    
    
    (5,125
    )Total partners deficits
    
    
    (24,414
    )
    
    
    (45,713
    )TOTAL LIABILITIES AND PARTNERS DEFICITS
    
    $
    356,684
    
    
    $
    339,955


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

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

Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,
    
    
    September 30,
    
    
    September 30,2003
    
    
    2002
    
    
    2003
    
    
    2002OPERATING REVENUES:Electric and steam
    
    $
    62,266
    
    
    $
    53,442
    
    
    $
    184,875
    
    
    $
    147,836Fuel revenues
    
    
    2,310
    
    
    
    4,834
    
    
    
    13,884
    
    
    
    16,819Total operating revenues
    
    
    64,576
    
    
    
    58,276
    
    
    
    198,759
    
    
    
    164,655COST OF REVENUES:Fuel and transmission costs
    
    
    35,579
    
    
    
    31,078
    
    
    
    112,286
    
    
    
    83,017Unrealized loss on derivative contracts
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    446Other operating and maintenance
    
    
    3,430
    
    
    
    2,996
    
    
    
    12,177
    
    
    
    20,297Depreciation
    
    
    3,148
    
    
    
    3,140
    
    
    
    9,427
    
    
    
    9,400Total cost of revenues
    
    
    42,157
    
    
    
    37,214
    
    
    
    133,890
    
    
    
    113,160GROSS PROFIT
    
    
    22,419
    
    
    
    21,062
    
    
    
    64,869
    
    
    
    51,495OTHER OPERATING EXPENSES:Administrative services, affiliates
    
    
    309
    
    
    
    425
    
    
    
    1,122
    
    
    
    1,126Other general and administrative
    
    
    913
    
    
    
    811
    
    
    
    2,227
    
    
    
    2,272Total other operating expenses
    
    
    1,222
    
    
    
    1,236
    
    
    
    3,349
    
    
    
    3,398OPERATING INCOME
    
    
    21,197
    
    
    
    19,826
    
    
    
    61,520
    
    
    
    48,097INTEREST (INCOME) EXPENSE:Interest income
    
    
    (123
    )
    
    
    (195
    )
    
    
    (455
    )
    
    
    (662
    )Interest expense
    
    
    7,812
    
    
    
    8,156
    
    
    
    23,806
    
    
    
    24,758Total interest expense, net
    
    
    7,689
    
    
    
    7,961
    
    
    
    23,351
    
    
    
    24,096INCOME BEFORE CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE
    
    $
    13,508
    
    
    $
    11,865
    
    
    $
    38,169
    
    
    $
    24,001CUMULATIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE
    
    
    
    
    
    
    
    
    
    
    (53
    )
    
    
    NET INCOME
    
    $
    13,508
    
    
    $
    11,865
    
    
    $
    38,116
    
    
    $
    24,001NET INCOME ALLOCATION:General partners
    
    $
    136
    
    
    $
    118
    
    
    $
    382
    
    
    $
    240Limited partners
    
    
    13,372
    
    
    
    11,747
    
    
    
    37,734
    
    
    
    23,761TOTAL
    
    $
    13,508
    
    
    $
    11,865
    
    
    $
    38,116
    
    
    $
    24,001


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
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,
    
    
    September 30,
    
    
    September 30,2003
    
    
    2002
    
    
    2003
    
    
    2002CASH FLOWS FROM OPERATING ACTIVITIES:Net income
    
    $
    13,508
    
    
    $
    11,865
    
    
    $
    38,116
    
    
    $
    24,001Adjustments to reconcile net income to net cash
provided by operating activities:Cumulative effect of a change in accounting principle
    
    
    
    
    
    
    
    
    
    
    53
    
    
    
    Depreciation, amortization and accretion
    
    
    3,405
    
    
    
    3,407
    
    
    
    10,210
    
    
    
    10,211Unrealized loss on derivative contracts
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    446Deferred revenue
    
    
    (177
    )
    
    
    (176
    )
    
    
    (531
    )
    
    
    (530
    )Loss on disposal of plant and equipment
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    481Increase (decrease) in cash resulting from a change in:Restricted funds
    
    
    (184
    )
    
    
    1,652
    
    
    
    (583
    )
    
    
    (1,750
    )Accounts receivable
    
    
    (1,184
    )
    
    
    106
    
    
    
    (2,277
    )
    
    
    (247
    )Due from affiliates
    
    
    
    
    
    
    801
    
    
    
    1,757
    
    
    
    932Fuel inventory and supplies
    
    
    (115
    )
    
    
    (646
    )
    
    
    398
    
    
    
    3,661Other current assets
    
    
    354
    
    
    
    316
    
    
    
    (816
    )
    
    
    (471
    )Accounts payable
    
    
    (429
    )
    
    
    (154
    )
    
    
    118
    
    
    
    (1,515
    )Accrued bond interest payable
    
    
    7,556
    
    
    
    7,888
    
    
    
    7,548
    
    
    
    7,882Accrued fuel expenses
    
    
    (543
    )
    
    
    (89
    )
    
    
    1,026
    
    
    
    723Accrued property taxes
    
    
    42
    
    
    
    44
    
    
    
    142
    
    
    
    948Accrued operating and maintenance expenses
    
    
    (207
    )
    
    
    (2,280
    )
    
    
    (192
    )
    
    
    32Other accrued expenses
    
    
    336
    
    
    
    310
    
    
    
    (545
    )
    
    
    (380
    )Due to affiliates
    
    
    131
    
    
    
    (756
    )
    
    
    (271
    )
    
    
    (1,489
    )Other long-term liabilities
    
    
    730
    
    
    
    730
    
    
    
    440
    
    
    
    541Net cash provided by operating activities
    
    
    23,223
    
    
    
    23,018
    
    
    
    54,593
    
    
    
    43,476CASH FLOWS FROM INVESTING ACTIVITIES:Plant and equipment additions
    
    
    (128
    )
    
    
    14
    
    
    
    (618
    )
    
    
    (2,101
    )Net cash provided by (used in) investing
activities
    
    
    (128
    )
    
    
    14
    
    
    
    (618
    )
    
    
    (2,101
    )CASH FLOWS FROM FINANCING ACTIVITIES:Restricted funds
    
    
    (26,032
    )
    
    
    (23,188
    )
    
    
    (26,032
    )
    
    
    (23,189
    )Distributions to partners
    
    
    (2,136
    )
    
    
    
    
    
    
    (20,711
    )
    
    
    (14,673
    )Repayment of long-term debt
    
    
    
    
    
    
    
    
    
    
    (8,498
    )
    
    
    (6,621
    )Net cash used in financing activities
    
    
    (28,168
    )
    
    
    (23,188
    )
    
    
    (55,241
    )
    
    
    (44,483
    )NET DECREASE IN CASH AND
CASH EQUIVALENTS
    
    
    (5,073
    )
    
    
    (156
    )
    
    
    (1,266
    )
    
    
    (3,108
    )CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD
    
    
    6,523
    
    
    
    1,594
    
    
    
    2,716
    
    
    
    4,546CASH AND CASH EQUIVALENTS,
END OF PERIOD
    
    $
    1,450
    
    
    $
    1,438
    
    
    $
    1,450
    
    
    $
    1,438SUPPLEMENTAL CASH FLOW INFORMATION:Cash paid for interest
    
    $
    
    
    
    $
    
    
    
    $
    15,479
    
    
    $
    16,064


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

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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 balance sheet at December
31, 2002, consolidated statements of operations for the three and nine months
ended September 30, 2002 and consolidated statements of cash flows for the
three and nine months ended September 30, 2002 to conform with the current
periods basis of presentation. Operating results for the three and nine
months ended September 30, 2003 are not necessarily indicative of the results
that may be expected for the year ending December 31, 2003.

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

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

Comprehensive Income

The Partnerships comprehensive income consists principally of net income and
changes in the market value of certain financial hedges under Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities, as amended (SFAS No. 133).

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

Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2003
    
    
    2002
    
    
    2003
    
    
    2002Net income
    
    $
    13,508
    
    
    $
    11,865
    
    
    $
    38,116
    
    
    $
    24,001Net gain (loss) from current period
hedging transactions in accordance
with SFAS No. 133
    
    
    (88
    )
    
    
    (1,204
    )
    
    
    2,870
    
    
    
    244Net reclassification to earnings
    
    
    263
    
    
    
    849
    
    
    
    1,024
    
    
    
    2,494Comprehensive income
    
    $
    13,683
    
    
    $
    11,510
    
    
    $
    42,010
    
    
    $
    26,739


Note 2. Significant Accounting Policies

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

Adoption of New Accounting Pronouncements

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

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

If this statement had been adopted on January 1, 2002, the pro forma effects on
earnings of the accounting change for the nine months ended September 30, 2002
would not have been material.

In June 2002, the Financial Accounting Standards Board (FASB) issued SFAS
No. 146, Accounting for Costs Associated with Exit or Disposal Activities,
which is effective for exit and disposal activities initiated after December
31, 2002. In November 2002, the FASB issued Interpretation No. 45, Guarantors
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others. This interpretation

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establishes new disclosure requirements for all guarantees, but the measurement
criteria are applicable to guarantees issued and modified after December 31,
2002. Both SFAS No. 146 and Interpretation No. 45 were adopted on January 1,
2003 and did not have an impact on the Partnerships consolidated financial
statements.

In April 2003, the FASB issued Statement No. 149, Amendment of Statement 133 on
Derivative Instruments and Hedging Activities(SFAS No. 149). SFAS No. 149
amends and clarifies the accounting and reporting for derivative instruments,
including certain derivatives embedded in other contracts, and for hedging
activities under SFAS No. 133. SFAS No. 149 clarifies under what circumstances
a contract with an initial net investment meets the characteristics of a
derivative according to SFAS No. 133 and when a derivative contains a financing
component that warrants special reporting in the statement of cash flows. The
provisions of SFAS No. 149 that relate to SFAS No. 133 implementation issues
that have been effective for periods that began prior to June 15, 2003, should
continue to be applied in accordance with their respective effective dates.
This statement was adopted on July 1, 2003 and did not have an impact on the
Partnerships consolidated financial statements.

Accounting Principles Issued But Not Yet Adopted

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

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

Note 3. Related Party Transactions

JMCS I Management, Inc., an affiliate of JMC Selkirk Inc., manages the
day-to-day operation of the Partnership and is compensated at agreed-upon
billing rates that are adjusted quadrennially in accordance with an
administrative services agreement. The cost of services provided by JMCS I
Management, Inc. are included in administrative services  affiliates in the
accompanying consolidated statements of operations. The total amount due to
JMCS I Management, Inc. at September 30, 2003 was approximately $268,000.

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

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

Nine months ended September 30,2003
    
    
    2002NEGT Energy Trading  Gas
    
    $
    4,901
    
    
    $
    7,885Pittsfield Generating
    
    
    39
    
    
    
    4MASSPOWER
    
    
    1,354
    
    
    
    42


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

Nine months ended September 30,2003
    
    
    2002NEGT Energy Trading  Gas
    
    $
    9,117
    
    
    $
    16,224ET Canada
    
    
    
    
    
    
    205Pittsfield Generating
    
    
    
    
    
    
    1MASSPOWER
    
    
    16
    
    
    
    59


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

The Partnership has two agreements with Iroquois Gas Transmission System
(IGTS), an affiliate of JMC Selkirk, Inc., to provide firm transportation of
natural gas from Canada. Firm fuel transportation services for the nine months
ended September 30, 2003 totaled approximately $5,275,000, compared to
approximately $5,552,000 for the same period in the prior year. These services
are recorded as fuel costs in the accompanying consolidated statements of
operations. The total amount due to IGTS for firm transportation at September
30, 2003 was approximately $556,000.

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Note 4. Accounting For Derivative Contracts

Currency Exchange Contracts

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

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

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

Three Months Ended
    
    
    Nine Months EndedSeptember 30,
    
    
    September 30,2003
    
    
    2002
    
    
    2003
    
    
    2002Beginning accumulated other
comprehensive loss at July 1
and January 1, respectively
    
    $
    (1,406
    )
    
    $
    (5,708
    )
    
    $
    (5,125
    )
    
    $
    (8,801
    )Net gain (loss) from current
period hedging transactions
    
    
    (88
    )
    
    
    (1,204
    )
    
    
    2,870
    
    
    
    244Net reclassification to earnings
    
    
    263
    
    
    
    849
    
    
    
    1,024
    
    
    
    2,494Ending accumulated other
comprehensive loss
    
    $
    (1,231
    )
    
    $
    (6,063
    )
    
    $
    (1,231
    )
    
    $
    (6,063
    )


Peak shaving arrangements

The Partnership enters into peak shaving arrangements whereby it grants to
local distribution companies or other purchasers a call on a specified portion
of the Partnerships firm natural gas supply for a specified number of days
during the winter season. Such arrangements are

8



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derivatives under SFAS No. 133. Changes in the fair value of these peak
shaving arrangements are recorded on the consolidated statements of operations
as an unrealized gain or loss on derivative contracts. The unrealized loss on
derivative contracts for the nine months ended September 30, 2002 was
approximately $446,000. The Partnership had not entered into any peak shaving
arrangements at September 30, 2003.

Note 5. Concentrations of Credit Risk

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

As of September 30, 2003, the Partnerships credit risk is primarily
concentrated with the following customers: Consolidated Edison Company of New
York, Inc., Niagara Mohawk Power Corporation and the New York Independent
System Operator, all of which are considered to be of investment grade.

Note 6. Relationship with National Energy & Gas Transmission, Inc. (NEGT,
formerly PG&E National Energy Group, Inc.)

JMC Selkirk, Inc. is the managing general partner of the Partnership.
Approximately 90% of the ownership interest in JMC Selkirk, Inc. is held by an
indirect subsidiary of NEGT. NEGT is an indirect subsidiary of PG&E
Corporation.

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

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

9



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

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

However, the Partnership cannot be certain that the NEGT Bankruptcy will not
affect NEGTs arrangements with respect to the Partnership or the ability of
JMC Selkirk, Inc. or JMCS I Management, Inc. to manage the Partnership. The
Partnership Agreement provides certain management rights to RCM Selkirk GP,
Inc. in the event that JMC Selkirk, Inc. were to be included in a bankruptcy
involving NEGT, or either JMC Selkirk, Inc. or JMCS I Management, Inc. were to
be in material default of its obligations to the Partnership (following notice
and a 120 day cure period), including (i) the removal of JMC Selkirk, Inc. as
the managing general partner, (ii) the appointment of itself as the successor
managing general partner, and (iii) the termination of the administrative
services agreement with JMCS I Management, Inc. and subsequent appointment of
a RCM Selkirk GP, Inc. affiliate as the project management firm. Enforcement
of these rights by RCM Selkirk GP, Inc. could, however, be delayed or impeded
as a result of any bankruptcy proceeding involving JMC Selkirk, Inc.
Moreover, the bankruptcy of any partner of the Partnership would be an event
of default under the Partnerships Credit Agreement.

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

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

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

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

10



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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.

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 agency focus on
the energy business with the potential for changes in industry regulations and

12



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in the treatment of the Partnership by state and federal agencies; changes in
or application of federal, state, and local laws and regulations to which the
Partnership is subject; and changes in or application of Canadian laws,
regulations, and policies which may impact the Partnership.

Litigation and Environmental Matters

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

Overview

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

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

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

JMC Selkirk, Inc. is the managing general partner of the Partnership.
Approximately 90% of the ownership interest in JMC Selkirk, Inc. is held by an
indirect subsidiary of NEGT. NEGT is an indirect subsidiary of PG&E
Corporation.

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

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: NEGT Energy
Trading-Power, L.P. (NEGT Energy Trading-Power, formerly PG&E Energy
TradingPower, L.P) and NEGT Energy Trading  Gas Corporation (NEGT Energy
Trading-Gas, formerly PG&E Energy TradingGas Corporation). As of May 31,
2003, the Partnership ceased transactions with NEGT Energy TradingPower and
NEGT Energy TradingGas. The Partnership believes there are sufficient
counterparties available with which to undertake transactions in the electric
and gas market and, therefore, the bankruptcy filings of NEGT Energy
TradingPower and NEGT Energy TradingGas will not have a material impact on
the results of operations of the Partnership.

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

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

However, the Partnership cannot be certain that the NEGT Bankruptcy will not
affect NEGTs arrangements with respect to the Partnership or the ability of
JMC Selkirk, Inc. or JMCS I Management, Inc. to manage the Partnership. The
Partnership Agreement provides certain management rights to RCM Selkirk GP,
Inc. in the event that JMC Selkirk, Inc. were to be included in a bankruptcy
involving NEGT, or either JMC Selkirk, Inc. or JMCS I Management, Inc. were to
be in material default of its obligations to the Partnership (following notice
and a 120 day cure period), including (i) the removal of JMC Selkirk, Inc. as
the managing general partner, (ii) the appointment of itself as the successor
managing general partner, and (iii) the termination of the administrative
services agreement with JMCS I Management, Inc. and subsequent appointment of
a RCM Selkirk GP, Inc. affiliate as the project management firm. Enforcement
of these rights by RCM Selkirk GP, Inc. could, however, be delayed or impeded
as a result of any bankruptcy proceeding involving JMC Selkirk, Inc.
Moreover, the bankruptcy of any partner of the Partnership would be an event
of default under the Partnerships Credit Agreement. 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.

14



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Results of Operations

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

Three Months Ended September 30,2003
    
    
    2002Volume
    
    
    Dollars
    
    
    Volume
    
    
    DollarsDispatch factor:Unit 1
    
    
    
    
    
    
    96.2
    %
    
    
    
    
    
    
    
    
    
    
    100.0
    %Unit 2
    
    
    
    
    
    
    98.2
    %
    
    
    
    
    
    
    
    
    
    
    100.0
    %Capacity factor:Unit 1
    
    
    
    
    
    
    82.3
    %
    
    
    
    
    
    
    
    
    
    
    87.0
    %Unit 2
    
    
    
    
    
    
    97.1
    %
    
    
    
    
    
    
    
    
    
    
    98.4
    %Electric and steam revenues:Unit 1 (Kwh)
    
    
    
    
    
    
    145.2
    
    
    $
    19.2
    
    
    
    
    
    
    
    153.6
    
    
    $
    15.3Unit 2 (Kwh)
    
    
    
    
    
    
    568.0
    
    
    
    43.1
    
    
    
    
    
    
    
    575.4
    
    
    
    38.1Steam (lbs)
    
    
    
    
    
    
    308.6
    
    
    
    
    
    
    
    
    
    
    
    383.3
    
    
    
    Total electric and steam revenues
    
    
    
    
    
    
    
    
    
    
    62.3
    
    
    
    
    
    
    
    
    
    
    
    53.4Fuel revenues:Gas resales (mmbtu)
    
    
    
    
    
    
    0.2
    
    
    
    0.8
    
    
    
    
    
    
    
    0.1
    
    
    
    0.4Gas optimizations (mmbtu)
    
    
    
    
    
    
    0.3
    
    
    
    1.5
    
    
    
    
    
    
    
    1.4
    
    
    
    4.4Peak shaving
arrangements (mmbtu)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total fuel revenues
    
    
    
    
    
    
    
    
    
    
    2.3
    
    
    
    
    
    
    
    
    
    
    
    4.8Total operating revenues
    
    
    
    
    
    
    
    
    
    $
    64.6
    
    
    
    
    
    
    
    
    
    
    $
    58.2


Nine Months Ended September 30,2003
    
    
    2002Volume
    
    
    Dollars
    
    
    Volume
    
    
    DollarsDispatch factor:Unit 1
    
    
    96.9
    %
    
    
    
    
    
    
    98.4
    %Unit 2
    
    
    90.9
    %
    
    
    
    
    
    
    85.2
    %Capacity factor:Unit 1
    
    
    89.5
    %
    
    
    
    
    
    
    94.1
    %Unit 2
    
    
    88.8
    %
    
    
    
    
    
    
    78.0
    %Electric and steam revenues:Unit 1 (Kwh)
    
    
    468.9
    
    
    $
    56.4
    
    
    
    491.9
    
    
    $
    42.9Unit 2 (Kwh)
    
    
    1,540.9
    
    
    
    128.5
    
    
    
    1,353.3
    
    
    
    104.8Steam (lbs)
    
    
    996.7
    
    
    
    
    
    
    
    1,052.5
    
    
    
    0.1Total electric and steam revenues
    
    
    
    
    
    
    184.9
    
    
    
    
    
    
    
    147.8Fuel revenues:Gas resales (mmbtu)
    
    
    1.4
    
    
    
    8.3
    
    
    
    2.7
    
    
    
    9.1Gas optimizations (mmbtu)
    
    
    0.5
    
    
    
    3.1
    
    
    
    2.3
    
    
    
    7.2Peak shaving
arrangements (mmbtu)
    
    
    0.2
    
    
    
    2.5
    
    
    
    
    
    
    
    0.5Total fuel revenues
    
    
    
    
    
    
    13.9
    
    
    
    
    
    
    
    16.8Total operating revenues
    
    
    
    
    
    $
    198.8
    
    
    
    
    
    
    $
    164.6


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

Overall Results

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

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

Operating Revenues

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

Cost of Revenues

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

16



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

Overall Results

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

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

Operating Revenues

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

Cost of Revenues

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

Liquidity and Capital Resources

Net cash provided by operating activities was $23.2 million for the three
months ended September 30, 2003, an increase of $0.2 million from the same
period in the prior year. Net cash provided by operating activities was $54.6
million for the nine months ended September 30, 2003, an increase of $11.1
million from the same period in the prior year. Net cash provided by operating
activities primarily represents net income, adjusted by non-cash

17



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##### 



expenses and income, plus the net effect of changes within the Partnerships
operating assets and liability accounts.

Net cash used in investing activities was $0.1 million for the three months
ended September 30, 2003, an increase of $0.1 million from the same period in
the prior year. Net cash used in investing activities was $0.6 million for the
nine months ended September 30, 2003, a decrease of $1.5 million from the same
period in the prior year. Net cash used in investing activities represents
additions to plant and equipment.

Net cash used in financing activities was $28.2 million for the three months
ended September 30, 2003, an increase of $5.0 million from the same period in
the prior year. Net cash used in financing activities was $55.2 million for
the nine months ended September 30, 2003, an increase of $10.8 million from the
same period in the prior year. These increases were primarily due to
additional cash becoming available to deposit into the Restricted Funds and
distribute to partners. Pursuant to the Partnerships Depositary and
Disbursement Agreement, administered by Bankers Trust Company, as depositary
agent, the Partnership is required to maintain certain Restricted Funds. Net
cash flows used in financing activities during the nine months ended September
30, 2003 and 2002 primarily represent the deposit of monies into the Interest,
Principal and Debt Service Reserve Funds, distributions to partners and the
semi-annual payment of principal and interest on long-term debt.

Credit Ratings

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

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

A downgrade of the credit ratings of the Partnerships debt due in 2007 or
2012 by S&P or Moodys (or both) would not be an event of default under any of
the Partnerships debt agreements and material project contracts or otherwise
result in an adverse change to any material term of such agreements and
contracts.

Credit Agreement

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

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

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

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

Market Risk

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

Interest Rate Risk

Interest rate risk is the risk that changes in interest rates could adversely
affect earnings or cash flows. The Partnerships cash and restricted cash are
sensitive to changes in interest rates. Interest rate changes would result in
a change in interest income due to the difference between the current interest
rates on cash and restricted cash and the variable rate that these financial
instruments may adjust to in the future. Interest rate risk sensitivity
analysis is used to measure interest rate risk by computing estimated changes
in cash flows as a result of assumed changes in market interest rates. As of
September 30, 2003, a 10% decrease in interest rates would be immaterial to the
Partnerships consolidated financial statements.

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

Foreign Currency Risk

Foreign currency risk is the risk of changes in value of pending financial
obligations in foreign currencies in relation to the U.S. dollar. The
Partnership uses currency swap agreements to partially hedge foreign currency
exposure under fuel transportation agreements that are denominated in Canadian
dollars. In the event a counterparty fails to meet the terms of the currency
swap agreements, the Partnership would be exposed to the risk that fluctuating
currency exchange rates may adversely impact its financial results.

The Partnership uses sensitivity analysis to measure its foreign currency
exchange rate exposure not covered by the currency swap agreements. Based upon
a sensitivity analysis at September 30, 2003, a 10% devaluation of the U.S.
Dollar in relation to the Canadian dollar would be immaterial to the
Partnerships consolidated financial statements.

Energy Commodity Price Risk

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

Credit Risk

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

As of September 30, 2003, the Partnerships credit risk is primarily
concentrated with the following customers: Consolidated Edison Company of New
York, Inc., Niagara Mohawk Power Corporation and the New York Independent
System Operator, all of which are considered to be of investment grade.

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Significant Commitments

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

Critical Accounting Policies

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

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

Accounting Principles Issued But Not Yet Adopted

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

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

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impacts of FIN No. 46s initial recognition, measurement, and disclosure
provisions and does not expect that implementation of this interpretation will
have a significant impact on its consolidated financial statements.

Legal Matters

The Partnership is a party in various legal proceedings and potential claims
arising in the ordinary course of its business. Management does not believe
that the resolution of these matters will have a material adverse effect on the
Partnerships consolidated financial position or results of operations. See
Part I, Item 3 of the Partnerships December 31, 2002 Annual Report on Form
10-K for further discussion of significant pending litigation.

Regulations and Environmental Matters

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
as of September 30, 2003, the principal executive officers and principal
financial officers of JMC Selkirk, Inc., as Managing General Partner of Selkirk
Cogen Partners, L.P., and Selkirk

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Cogen Funding Corporation have concluded that such controls and procedures
effectively ensure that information required to be disclosed by the Partnership
in reports the Partnership files or submits under the Securities and Exchange
Act of 1934 is recorded, processed, summarized, and reported within the time
periods specified in the Securities and Exchange Commission (SEC) rules and
forms.

Changes in Internal Controls

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















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PART II.          OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(A)  Exhibits

Exhibit No.
    
    Description of Exhibit31.1
    
    Certification of Principal Executive Officer of JMC Selkirk, Inc., as
Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to
Section 302 of the Sarbanes  Oxley Act of 2002 dated November 13, 200331.2
    
    Certification of Principal Financial Officer of JMC Selkirk, Inc., as
Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to
Section 302 of the Sarbanes  Oxley Act of 2002 dated November 13, 200331.3
    
    Certification of Principal Executive Officer of Selkirk Cogen Funding
Corporation, pursuant to Section 302 of the Sarbanes  Oxley Act of 2002
dated November 13, 200331.4
    
    Certification of Principal Financial Officer of Selkirk Cogen Funding
Corporation, pursuant to Section 302 of the Sarbanes  Oxley Act of 2002
dated November 13, 200332.1
    
    Certification of Principal Executive Officer of JMC Selkirk, Inc., as
Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to
Section 906 of the Sarbanes  Oxley Act of 2002 dated November 13, 200332.2
    
    Certification of Principal Financial Officer of JMC Selkirk, Inc., as
Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to
Section 906 of the Sarbanes  Oxley Act of 2002 dated November 13, 200332.3
    
    Certification of Principal Executive Officer of Selkirk Cogen Funding
Corporation, pursuant to Section 906 of the Sarbanes  Oxley Act of 2002
dated November 13, 200332.4
    
    Certification of Principal Financial Officer of Selkirk Cogen Funding
Corporation, pursuant to Section 906 of the Sarbanes  Oxley Act of 2002
dated November 13, 2003


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|(B) |  | Reports on Form 8-K
|--- |  | -------------------



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

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





















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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 PartnerDate: November 13, 2003
    
    /s/ THOMAS E. LEGROName:
    
    Thomas E. LegroTitle:
    
    Vice President, Controller, Chief
Accounting Officer and DirectorSELKIRK COGEN FUNDING
CORPORATIONDate: November 13, 2003
    
    /s/ THOMAS E. LEGROName:
    
    Thomas E. LegroTitle:
    
    Vice President, Controller, Chief
Accounting Officer and Director












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EXHIBIT INDEX

Exhibit No.
    
    Description of Exhibit31.1
    
    Certification of Principal Executive Officer of JMC Selkirk, Inc., as
Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to
Section 302 of the Sarbanes  Oxley Act of 2002 dated November 13, 200331.2
    
    Certification of Principal Financial Officer of JMC Selkirk, Inc., as
Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to
Section 302 of the Sarbanes  Oxley Act of 2002 dated November 13, 200331.3
    
    Certification of Principal Executive Officer of Selkirk Cogen Funding
Corporation, pursuant to Section 302 of the Sarbanes  Oxley Act of 2002
dated November 13, 200331.4
    
    Certification of Principal Financial Officer of Selkirk Cogen Funding
Corporation, pursuant to Section 302 of the Sarbanes  Oxley Act of 2002
dated November 13, 200332.1
    
    Certification of Principal Executive Officer of JMC Selkirk, Inc., as
Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to
Section 906 of the Sarbanes  Oxley Act of 2002 dated November 13, 200332.2
    
    Certification of Principal Financial Officer of JMC Selkirk, Inc., as
Managing General Partner of Selkirk Cogen Partners, L.P., pursuant to
Section 906 of the Sarbanes  Oxley Act of 2002 dated November 13, 200332.3
    
    Certification of Principal Executive Officer of Selkirk Cogen Funding
Corporation, pursuant to Section 906 of the Sarbanes  Oxley Act of 2002
dated November 13, 200332.4
    
    Certification of Principal Financial Officer of Selkirk Cogen Funding
Corporation, pursuant to Section 906 of the Sarbanes  Oxley Act of 2002
dated November 13, 2003