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UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549FORM 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, 2002Commission File Number 33-83618

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

Delaware
          
          
          
          
          
          
          
          
51-0324332
          
   
(State or other jurisdiction of
          
          
          
          
(I.R.S. Employer Identification Number)
          
   
incorporation or organization)

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

Delaware
          
          
          
          
          
          
          
          
51-0354675
          
   
(State or other jurisdiction of
          
          
          
          
(I.R.S. Employer Identification Number)
   
          
incorporation or organization)

One Bowdoin Square, Boston, Massachusetts 02114
          (Address of principal executive offices, including zip code)(617) 788-3000
              (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 __

        

     As of November 13, 2002,  there  were 10 shares of common  stock of Selkirk
Cogen Funding Corporation, $1 par value outstanding.


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TABLE OF CONTENTS

`Page
                                                                          ----
                      PART I. FINANCIAL INFORMATION

Item 1.   Financial Statements (unaudited)

          Consolidated Balance Sheets as of September 30, 2002
          and December 31, 2001.......................................      1

          Consolidated Statements of Operations for the three and nine
          months ended September 30, 2002 and 2001...................       2

          Consolidated Statements of Cash Flows for the three and nine
          months ended September 30, 2002 and 2001....................      3

          Notes to Consolidated Financial Statements..................      4

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

          Results of Operations.......................................     11

          Liquidity and Capital Resources.............................     15

Item 3.   Quantitative and Qualitative Disclosures About Market Risk..     21

Item 4.   Controls and Procedures.....................................     22


                        PART II. OTHER INFORMATION

Item 6.   Exhibits and Reports on Form 8-K............................     23

SIGNATURES AND CERTIFICATIONS.........................................     24`

i

`SELKIRK COGEN PARTNERS, L.P.
                           CONSOLIDATED BALANCE SHEETS
                                 (In Thousands)
                                                                            September 30,       December 31,
                                                                                2002               2001
                                                                           ---------------    ---------------
ASSETS

CURRENT ASSETS:
    Cash and cash equivalents                                                 $     1,438        $     4,546
    Restricted funds                                                               26,357              7,699
    Accounts receivable, net of allowance of $0 and $32, respectively              18,036             17,789
    Due from affiliates                                                               195              1,127
    Fuel inventory and supplies                                                     6,567             10,228
    Other current assets                                                              982                511
    Asset for derivative contracts                                                    ---                446
                                                                           ---------------    ---------------
               Total current assets                                                53,575             42,346
                                                                           ---------------    ---------------

PLANT AND EQUIPMENT:
    Plant and equipment, at cost                                                  374,931            373,476
    Less: Accumulated depreciation                                                108,798             99,563
                                                                           ---------------    ---------------
               Plant and equipment, net                                           266,133            273,913
                                                                           ---------------    ---------------
LONG-TERM RESTRICTED FUNDS                                                         30,595             24,314

DEFERRED FINANCING CHARGES, net of accumulated
     amortization of $9,712 and $8,901, respectively                                6,579              7,390
                                                                           ---------------    ---------------
TOTAL ASSETS                                                                  $   356,882        $   347,963
                                                                           ===============    ===============

LIABILITIES AND PARTNERS' DEFICITS

CURRENT LIABILITIES:
    Accounts payable                                                            $     214         $    1,729
    Accrued bond interest payable                                                   8,239                357
    Accrued fuel expenses                                                           9,562              8,689
    Accrued property taxes                                                          3,244              2,296
    Accrued operating and maintenance expenses                                      1,294              1,262
    Other accrued expenses                                                          3,793              4,173
    Due to affiliates                                                                 369              2,008
    Current portion of long-term bonds                                             15,406             13,529
    Current portion of liability for derivative contracts                           2,858              3,688
                                                                           ---------------    ---------------
               Total current liabilities                                           44,979             37,731

LONG-TERM LIABILITIES:
    Deferred revenue                                                                4,067              4,597
    Other long-term liabilities                                                     7,611              7,070
    Long-term bonds - net of current portion                                      340,737            349,235
    Liability for derivative contracts - net of current
    portion                                                                         3,205              5,113
                                                                           ---------------    ---------------
               Total liabilities                                                  400,599            403,746
                                                                           ---------------    ---------------

COMMITMENTS AND CONTINGENCIES

PARTNERS' DEFICITS:
    General partners' deficits                                                      (369)              (458)
    Limited partners' deficits                                                   (37,285)           (46,524)
    Accumulated other comprehensive loss                                          (6,063)            (8,801)
                                                                           ---------------    ---------------
               Total partners' deficits                                          (43,717)           (55,783)
                                                                           ---------------    ---------------
TOTAL LIABILITIES AND PARTNERS' DEFICITS                                      $   356,882        $   347,963
                                                                           ===============    ===============

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

1

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


                                                         For the Three Months Ended          For the Nine Months Ended
                                                      ---------------------------------   ---------------------------------

                                                       September 30,    September 30,      September 30,    September 30,
                                                           2002              2001              2002              2001
                                                      ----------------  ---------------   ----------------  ---------------
OPERATING REVENUES:
     Electric and steam                                    $   53,442       $   52,433        $   147,836      $   159,944
     Fuel revenues                                              4,834              691             16,819           17,330
                                                                                          ----------------  ---------------
                                                      ----------------  ---------------
              Total operating revenues                         58,276           53,124            164,655          177,274
                                                      ----------------  ---------------   ----------------  ---------------

COST OF REVENUES:
     Fuel and transmission costs                               31,078           26,541             83,017           99,396
     Unrealized loss on derivative contracts                      ---              ---                446              ---
     Other operating and maintenance                            2,996            3,727             20,297           14,264
     Depreciation                                               3,140            3,125              9,400            9,363
                                                      ----------------  ---------------   ----------------  ---------------
              Total cost of revenues                           37,214           33,393            113,160          123,023
                                                      ----------------  ---------------   ----------------  ---------------
GROSS PROFIT                                                   21,062           19,731             51,495           54,251
                                                      ----------------  ---------------   ----------------  ---------------

OTHER OPERATING EXPENSES:
     Administrative services, affiliates                          425              478              1,126            1,448
     Other general and administrative                             811              609              2,272            1,891
     Amortization of deferred financing charges                   267              276                811              836
                                                      ----------------  ---------------   ----------------  ---------------
              Total other operating expenses                    1,503            1,363              4,209            4,175
                                                      ----------------  ---------------   ----------------  ---------------

OPERATING INCOME                                               19,559           18,368             47,286           50,076
                                                      ----------------  ---------------   ----------------  ---------------

INTEREST (INCOME) EXPENSE:
     Interest income                                            (195)            (377)              (662)          (1,682)
     Interest expense                                           7,889            8,141             23,947           24,678
                                                      ----------------  ---------------    ----------------  ---------------
              Total interest expense, net                       7,694            7,764             23,285           22,996
                                                      ----------------  ---------------   ----------------  ---------------


Income before cumulative effect of a change
     in accounting principle                                   11,865           10,604             24,001           27,080

Cumulative effect of a change in
     accounting principle                                         ---            (519)                ---            (519)
                                                      ----------------  ---------------   ----------------  ---------------

NET INCOME                                                 $   11,865       $   10,085         $   24,001       $   26,561
                                                      ================  ===============   ================  ===============

NET INCOME ALLOCATION:
     General partners                                      $      118        $     101         $     240        $     266
     Limited partners                                          11,747            9,984            23,761           26,295
                                                      ---------------   ----------------  ---------------  ----------------
     TOTAL                                                 $   11,865        $  10,085         $  24,001        $  25,561
                                                      ================  ===============   ================  ===============


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

2

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

                                                             For the Three Months Ended      For the Nine Months Ended
                                                            -----------------------------  -------------------------------
                                                            September 30,  September 30,   September 30,   September 30,
                                                                2002           2001             2002            2001
                                                            -------------- --------------  --------------- ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
     Net income                                                $   11,865     $   10,085       $   24,001     $    26,561
     Adjustments to reconcile net income to net cash
        provided by operating activities:
        Cumulative effect of change in accounting                                                                     519
        principle                                                     ---            519              ---
        Depreciation and amortization                               3,407          3,401           10,211          10,199
        Unrealized loss on derivative contracts                       ---            ---              446             ---
        Deferred revenue                                            (176)          (176)            (530)           (530)
        Loss on disposal of plant and equipment                       ---             59              481              91
        Increase (decrease) in cash resulting from a
        change in:
           Restricted funds                                         1,652            558          (1,750)           1,450
           Accounts receivable                                        106            509            (247)           2,467
           Due from affiliates                                        801            528              932           3,763
           Fuel inventory and supplies                              (646)        (1,194)            3,661         (3,227)
           Other current assets                                       316            330            (471)           (490)
           Accounts payable                                         (154)            870          (1,515)             821
           Accrued bond interest payable                            7,888          8,141            7,882           8,135
           Accrued fuel expenses                                    (105)        (1,298)              873         (5,965)
           Accrued property taxes                                      44            ---              948             100
           Accrued operating and maintenance expenses             (2,280)          (154)               32           (430)
           Other accrued expenses                                     310            556            (380)           1,826
           Due to affiliates                                        (740)        (1,331)          (1,639)             342
           Other long-term liabilities                                730            730              541             641
                                                            -------------- --------------  --------------- ---------------
            Net cash provided by operating activities              23,018         22,133           43,476          46,273
                                                            -------------- --------------  --------------- ---------------
CASH FLOWS FROM INVESTING ACTIVITIES:
     Plant and equipment additions                                     14            (3)          (2,101)           (919)
     Proceeds from disposal of plant and equipment                    ---            ---              ---              10
                                                            -------------- --------------  --------------- ---------------
            Net cash provided by (used in) investing                   14            (3)          (2,101)           (909)
            activities                                      -------------- --------------  --------------- ---------------

CASH FLOWS FROM FINANCING ACTIVITIES:
     Restricted funds                                            (23,188)       (21,670)         (23,189)        (21,670)
     Distributions to partners                                        ---        (1,314)         (14,673)        (18,859)
     Repayment of long-term debt                                      ---            ---          (6,621)         (6,010)
                                                            -------------- --------------  --------------- ---------------
            Net cash used in financing activities                (23,188)       (22,984)         (44,483)        (46,539)
                                                            -------------- --------------  --------------- ---------------

NET DECREASE IN CASH AND CASH EQUIVALENTS                           (156)          (854)          (3,108)         (1,175)
                                                            -------------- --------------  --------------- ---------------
CASH AND CASH EQUIVALENTS,
    BEGINNING OF PERIOD                                             1,594          2,866            4,546           3,187
                                                            -------------- --------------  --------------- ---------------

CASH AND CASH EQUIVALENTS,
    END OF PERIOD                                              $    1,438     $    2,012       $    1,438     $     2,012
                                                            ============== ==============  =============== ===============
SUPPLEMENTAL CASH FLOW INFORMATION:
      Cash paid for interest                                   $      ---     $      ---       $   16,064     $    16,543
                                                            ============== ==============  =============== ===============

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

3

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
nine months ended  September 30, 2001 to conform with the current  periods
basis of  presentation.  Operating  results for the three and nine months  ended
September  30, 2002 are not  necessarily  indicative  of the results that may be
expected for the year ended December 31, 2002.

These consolidated  financial  statements should be read in conjunction with the
audited  consolidated  financial  statements included in the  Partnerships
December 31, 2001 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).

4

The schedule below summarizes the activities affecting  comprehensive income for
the three and nine months ended September 30, 2002 and 2001 (in millions):

`Three Months Ended                 Nine Months Ended
                                                     September 30,                     September 30,
                                             ------------------------------     ----------------------------
                                                 2002             2001              2002           2001
                                             -------------    -------------     -------------  -------------
Net income                                       $   11.9         $   10.1          $   24.0        $  26.6
Cumulative effect of adoption of
   SFAS No. 133                                       ---              ---               ---          (9.0)
Net gain (loss) from current period
   hedging transactions in accordance
   with SFAS No. 133                                (1.2)            (1.3)               0.2          (2.4)

Net reclassification to earnings                      0.8              0.8               2.5            2.3
                                             -------------    -------------     -------------  -------------
Comprehensive income                             $   11.5          $   9.6          $   26.7        $  17.5
                                             =============    =============     =============  =============`

Note 2. Significant Accounting Policies

Except as disclosed, the Partnership is following the same accounting principles
discussed  in the  Partnerships  December  31, 2001 Annual  Report on Form
10-K.Adoption of New Accounting Pronouncements

On April 1, 2002, the Partnership  implemented two interpretations issued by the
Financial  Accounting  Standard  Boards   (FASB)   Derivatives
Implementation  Group  (DIG).  DIG  Issues C15 and C16  changed  the
definition of normal  purchases and sales included in SFAS No. 133.  Previously,
certain derivative commodity contracts for the physical delivery of purchase and
sale quantities transacted in the normal course of business were exempt from the
requirements of SFAS No. 133 under the normal purchases and sales exemption, and
thus were not  marked-to-market  and  reflected on the balance  sheet like other
derivatives.  Instead,  these  contracts  were  recorded  on an  accrual  basis.

DIG Issue C15 changed the  definition of normal  purchases and sales for certain
power  contracts.  The  Partnership  determined  that all of its power contracts
continue to qualify for the normal purchases and sales exemption.  DIG Issue C16
disallowed  normal purchases and sales treatment for commodity  contracts (other
than power contracts) that contain  volumetric  variability or optionality.  The
Partnership  determined  that one of its  long-term  fuel  contracts  failed  to
continue  qualifying for the normal purchase exemption under the requirements of
DIG Issue  C16.   However,  because the long term fuel  contract has market
based pricing,  the Partnership  currently estimates its fair value to always be
zero, resulting in no impact to the  Partnerships  consolidated  financial
statements.

5

In June 2001,  the FASB issued SFAS No. 141,  entitled,  Business  Combinations.
This  statement  prohibits  the  use  of  the  pooling-of-interests   method  of
accounting for business  combinations  initiated after June 30, 2001 and applies
to all business  combinations  accounted for under the purchase  method that are
completed  after June 30, 2001.  This  statement was adopted on January 1, 2002,
and did not have an  impact  on the  Partnerships  consolidated  financial
statements.

Also in June 2001,  the FASB issued SFAS No. 142,  entitled,  Goodwill and Other
Intangible Assets. This statement  eliminates the amortization of goodwill,  and
requires  goodwill to be reviewed  periodically  for impairment.  This statement
also requires the useful lives of previously  recognized intangible assets to be
reassessed and the remaining  amortization  periods to be adjusted  accordingly.
This statement is effective for fiscal years  beginning after December 15, 2001,
for   all   goodwill   and   other   intangible   assets   recognized   on   the
Partnerships  consolidated balance sheets at that date, regardless of when
the assets were initially  recognized.  This statement was adopted on January 1,
2002,  and  did  not  have  an  impact  on the  Partnerships  consolidated
financial statements.

In August  2001,  the FASB  issued SFAS No. 144,  entitled,  Accounting  for the
Impairment or Disposal of Long-Lived  Assets.  SFAS No. 144 supercedes  SFAS No.
121,  entitled,  Accounting  for the  Impairment  of  Long-Lived  Assets and for
Long-Lived Assets to be Disposed of, but retains its fundamental  provisions for
recognizing and measuring  impairment of long-lived  assets to be held and used.
This  statement  also requires that all  long-lived  assets to be disposed of by
sale are  carried  at the lower of  carrying  amount or fair  value less cost to
sell, and that depreciation should cease to be recorded on such assets. SFAS No.
144 standardizes the accounting and presentation requirements for all long-lived
assets to be disposed of by sale, superceding previous guidance for discontinued
operations of business  segments.  This  statement is effective for fiscal years
beginning  after  December 15, 2001.  This  statement  was adopted on January 1,
2002,  and  did  not  have  an  impact  on the  Partnerships  consolidated
financial statements.Related Party Transactions

JMCS I Management,  Inc. (JMCS I Management)  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.  All officers and directors of JMC Selkirk,  Inc.,  are also officers
and directors of JMCS I Management. For the nine months ended September 30, 2002
and 2001,  expenses incurred for services provided by JMCS I Management  totaled
approximately $1.1 million and $1.5 million,  respectively. The cost of services
provided by JMCS I Management  was included in  administrative  services  
affiliates in the accompanying consolidated statements of operations.  The total
amount due to JMCS I Management  for these  services at September 30, 2002,  was
approximately $0.4 million.

6

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 purchased from PG&E Energy Trading  Gas,  Pittsfield and MASSPOWER
for the nine months  ended  September  30, 2002 totaled  approximately  $7,884.8
thousand,  $3.7 thousand and $41.9  thousand,  respectively.  Gas purchased from
PG&E Energy Trading  Gas, Pittsfield and MASSPOWER for the nine months
ended September 30, 2001 totaled approximately $2,677.8 thousand, $35.8 thousand
and $2,535.5 thousand,  respectively. Gas sold to PG&E Energy Trading 
Gas,  PG&E  Energy Trading   Canada,  Pittsfield and MASSPOWER for the
nine months ended September 30, 2002 totaled  approximately  $16,223.7 thousand,
$204.6  thousand,  $0.5 thousand and $58.7 thousand,  respectively.  Gas sold to
PG&E  Energy  Trading    Gas and  Pittsfield for the nine months ended
September 30, 2001 totaled approximately  $15,209.5 thousand and $79.8 thousand,
respectively.  Gas  purchases  were recorded as fuel costs and sales of gas were
recorded  as  fuel  revenues  in the  accompanying  consolidated  statements  of
operations.  The total  amount due to PG&E  Energy  Trading    Gas for
purchases of gas at September 30, 2002 was approximately  $15.5 thousand and the
total amount due from PG&E  Energy  Trading    Gas for sales of gas at
September 30, 2002 was approximately $140.2 thousand.

In May 1996, the  Partnership  entered into an enabling  agreement with PG&E
Energy  Trading    Power,  L.P.  ("PG&E  Energy  Trading-Power"),  an
affiliate of JMC Selkirk, Inc., to purchase and sell electric capacity, electric
energy, and other electric-related products. For the nine months ended September
30,  2002 and 2001,  sales to  PG&E  Energy  Trading    Power  totaled
approximately  $1.6 million and $3.8  million,  respectively.  Sales to PG&E
Energy  Trading     Power  were  recorded  as  electric  revenues  in  the
accompanying  consolidated  statements of operations.  The total amount due from
PG&E Energy Trading  Power at September 30, 2002 for sales of electric
capacity was approximately $0.1 million.

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.  For the nine months ended September
30, 2002, firm fuel transportation services from IGTS totaled approximately $5.6
million and $5.8  million,  respectively.  These  services were recorded as fuel
costs in the  accompanying  consolidated  statements  of  operations.  The total
amount due IGTS for firm transportation at September 30, 2002, was approximately
$0.6 million.

Note 3. Accounting For Derivative Contracts

The Partnership  has two foreign  currency  exchange  contracts to hedge against
fluctuations  in fuel  transportation  costs,  which are denominated in Canadian
dollars. For the three months ended September 30, 2002 and 2001, amounts charged
to fuel  costs as a result of  losses  realized  from  these  contracts  totaled
approximately  $0.8 million for each of the  periods.  For the nine months ended
September 30, 2002 and 2001, amounts charged to fuel costs as a result of losses
realized  from these  contracts  totaled  approximately  $2.5  million  and $2.3
million,  respectively.  The Partnership  expects that net derivative  losses of
approximately $2.9 million,  included in accumulated other comprehensive loss as
of September 30, 2002, will be reclassified into earnings within the next twelve
months.  The actual amounts  reclassified from accumulated  other  comprehensive
loss to  earnings  will  differ  as a  result  of  changes  in  exchange  rates.

7

The  schedule  below  summarizes  the  activities  affecting  accumulated  other
comprehensive  loss from  derivative  contracts  for the three  months  and nine
months ended September 30, 2002 and 2001 (in millions):

`Three Months Ended                 Nine Months Ended
                                                     September 30,                     September 30,
                                             ------------------------------     ----------------------------
                                                 2002             2001              2002           2001
                                             -------------    -------------     -------------  -------------
Beginning accumulated other
    comprehensive loss at July 1 and
    January 1, respectively                    $  (5.7)         $  (8.6)          $  (8.8)       $  (9.0)

Net gain (loss) from current
     period hedging transactions                  (1.2)            (1.3)               0.2          (2.4)

Net reclassification to earnings                   0.8              0.8               2.5            2.3
                                             -------------    -------------     -------------  -------------
Ending accumulated other comprehensive loss    $  (6.1)         $  (9.1)          $  (6.1)       $  (9.1)
                                             =============    =============     =============  =============`

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.  Revenues from peak shaving  arrangements for the nine months
ended  September 30, 2002 and 2001 were  approximately  $0.5 million for each of
the  periods.  On  July  1,  2001,  the  Partnership   determined  peak  shaving
arrangements  were no longer  exempt from the  requirements  of SFAS No. 133 and
recorded a loss of approximately  $0.5 million  reflecting the cumulative effect
of a change in accounting  principle.  Changes in the fair value of peak shaving
arrangements  are recorded on the  consolidated  statements  of operations as an
unrealized gain or loss on derivative  contracts.  Unrealized loss on derivative
contracts   for  the  nine  months  ended   September  30,  2002  and  2001  was
approximately $0.4 million and $0, respectively.

Note 4. Concentrations of Credit Risk

Credit risk is the risk of loss the  Partnership  would incur if  counterparties
were to fail to perform their contractual obligations (accounts receivable). 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.

8

As of  September  30,  2002,  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. During the three
months  ended   September  30,  2002,   the  parent  company  of  three  of  the
Partnerships  customers, all of whom are related parties,  PG&E Energy
Trading   Gas,  PG&E Energy Trading   Canada and PG&E Energy
Trading       Power   was   downgraded   below   investment   grade.   The
Partnerships net credit exposure to PG&E Energy Trading  Gas and
PG&E  Energy  Trading   Power at September 30, 2002 was  approximately
$0.1 million and $0.1 million, respectively.

Note 5. Relationship with Affiliated CompaniesBankruptcy of Pacific Gas and Electric Company

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

In December 2000, and in January and February 2001, PG&E Corporation and NEG
completed a corporate  restructuring of NEG that involved the use or creation of
limited liability companies  (LLCs) as intermediate owners between a
parent  company and its  subsidiaries.  One of these LLCs is  PG&E  National
Energy Group,  LLC, which owns 100% of the stock of NEG. After the restructuring
was  completed,  two  independent  rating  agencies,  Standard  and  Poors
(S&P)       and       Moodys       Investor       Services
(Moodys)   issued   investment   grade  ratings  for  NEG  and
reaffirmed  such  ratings for certain NEG  subsidiaries.  On April 6, 2001,  the
Utility filed a voluntary petition for relief under the provisions of Chapter 11
of the U.S. Bankruptcy Code  (Bankruptcy  Code) in the United States
Bankruptcy  Court for the  Northern  District  of  California  (Bankruptcy
Court).  Pursuant to the Bankruptcy  Code, the Utility  retains control of
its assets and is authorized  to operate its business as a  debtor-in-possession
while being subject to the jurisdiction of the Bankruptcy Court. The Utility and
PG&E  Corporation  have  jointly  filed a plan of  reorganization  with  the
Bankruptcy  Court  that  entails  separating  the  Utility  into  four  distinct
businesses.  The proposed plan of reorganization does not directly affect NEG or
any of its subsidiaries.  The Managing General Partner believes that NEG and its
direct  and  indirect  subsidiaries,   including  JMC  Selkirk,  Inc.,  Pentagen
Investors,  L.P. and the Partnership,  would not be  substantively  consolidated
with PG&E  Corporation in any insolvency or bankruptcy  proceeding involving
PG&E Corporation or the Utility.

9

NEG Rating Actions

Currently,  NEG is experiencing  liquidity  problems due to the deterioration in
PG&E  Corporations  credit position, the Utilitys bankruptcy and
the  downturn  in the  energy  industry.  On July 31,  2002 and  August 5, 2002,
S&P  and  Moodys,  respectively,  downgraded  NEGs  ratings,  as
previously reported.  On October 8, 2002, October 16, 2002 and October 18, 2002,
Moodys further downgraded the senior unsecured debt rating,  issuer rating
and syndicated bank credit facilities of NEG. Moodys current rating of NEG
is  B3".  On October 11, 2002,  S&P further downgraded certain of
NEGs   debt   facilities.   S&Ps   current   rating  of  NEG  is
B-".  The result of these  downgrades  has left the credit ratings of
NEG  and  its  debt  instruments   below  investment  grade.  Both  S&P  and
Moodys  credit ratings assigned to NEG and its affiliates are under review
for possible  further  downgrade.  The credit  rating  agency  action has had no
material  impact on the  financial  condition  or results of  operations  of the
Partnership.

On October 8, 2002,  Moodys  stated that in conjunction with the downgrade
of NEG it had  placed the  Partnerships  debt  under  review for  possible
downgrade.  On October 15, 2002, S&P stated that the recent downgrade of NEG
will not have an affect on the  rating  of the  Partnerships  debt at this
time.  S&Ps rating of the Partnerships debt is BBB-".
On November 5, 2002,  Moodys  issued an opinion update changing the rating
outlook  of the  Partnerships  debt to  under  review  for  possible
downgrade  from stable  for the Partnerships debt due in
2007 and negative  outlook  for the  Partnerships  debt due in
2012.  Moodys rating of the  Partnerships  debt is Baa3".


Note 6. Title V Permit

On November 6, 2001, the Partnership received from the New York State Department
of Environmental  Conservation (the 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.  The DEC has  confirmed  that the  terms and
conditions of the Title V Permit are stayed  pending a final DEC decision on the
appeal.  Since November 12, 2001, the  Partnership and DEC staff have engaged in
negotiations  regarding the Title V Permit. 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.

10

ITEM 2.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
                 
CONDITION AND RESULTS OF OPERATIONSCautionary Statement Regarding Forward-Looking Statements

Certain statements included herein are forward-looking statements concerning the
Partnerships  operations,  economic  performance and financial  condition.
Such statements are subject to various risks and  uncertainties.  Actual results
could differ  materially  from those  currently  anticipated  due to a number of
factors,  including general business and economic conditions; the performance of
equipment;  levels of dispatch;  the receipt of certain capacity and other fixed
payments;  electricity  prices;  natural gas resale prices;  fuel deliveries and
prices; the consequences, if any, of a potential downgrade of the credit ratings
for the  Partnerships  debt,  and the  renewal  of the  Partnerships
credit   agreement,   both  as   described   in   Liquidity   and  Capital
Resources  below; the outcome of the negotiations  with the New York State
Department of Environmental  Conservation  regarding the Facilitys Title V
operating   permit  as  described   in   Regulations   and   Environmental
Matters  below; and whether  Consolidated Edison Company of New York, Inc.
(Con  Edison)  were to prevail in its claim to Unit 2s  excess
natural gas volumes as described in the  Partnership's  December 31, 2001 Annual
Report on Form 10-K.Results of OperationsThree and Nine Months Ended September 30, 2002 Compared to the Three and 
Nine Months Ended September 30, 2001

The Partnership  earned net income of approximately  $11.9 million for the three
months ended September 30, 2002 as compared to  approximately  $10.1 million for
the corresponding period in the prior year. The Partnership earned net income of
approximately  $24.0  million for the nine months  ended  September  30, 2002 as
compared to  approximately  $26.6  million for the  corresponding  period in the
prior year.  The $1.8 million  increase in net income for the three months ended
September  30,  2002 was  primarily  due to  higher  operating  revenues,  lower
maintenance  expenses and the Partnership  recording a loss in the prior year of
approximately  $0.5  million  reflecting  the  cumulative  effect of a change in
accounting  principle.  The $2.6  million  decrease  in net  income for the nine
months ended September 30, 2002 was primarily due to higher maintenance expenses
resulting from  differences in the scheduling and scope of planned  maintenance,
partially offset by lower fuel costs.

Effective July 1, 2001, the Partnership determined that certain gas contracts no
longer  meet the  definition  of  normal  purchases  and sales and are no longer
exempt from the  requirements  of Statement of  Financial  Accounting  Standards
(SFAS)  No. 133,  Accounting  for Derivative  Instruments  and
Hedging Activities,  as amended by SFAS Nos. 137 and 138, Accounting
for  Certain  Derivative   Instruments  and  Certain  Hedging   Activities
(collectively,  SFAS No. 133). The  cumulative  effect of a change in accounting
principle was a loss of approximately  $0.5 million.  Future changes in the fair
value of the contracts will be recorded on the income statement as an unrealized
gain or loss on derivative contracts.

11

Total operating  revenues for the three and nine months ended September 30, 2002
were approximately $58.3 million and $164.7 million as compared to approximately
$53.1  million  and $177.3  million for the  corresponding  periods in the prior
year.

`Electric Revenues (dollars and kWh's in millions):
--------------------------------------------------

                                            For the Three Months Ended
                              September 30, 2002                          September 30, 2001
------------------------------------------------------------   -------------------------------------------
                        Dollars   kWh's   Capacity  Dispatch      Dollars    kWh's   Capacity   Dispatch
                        -------   -----   --------  --------      -------    ------  --------   --------
Unit 1                 15.3      153.6    87.0%     100.0%          16.0     158.4     89.8%      99.9%
Unit 2                 38.1      575.4    98.4%     100.0%          36.8     573.1     97.8%     100.0%

                                            For the Nine Months Ended
                              September 30, 2002                         September 30, 2001
------------------------------------------------------------   -------------------------------------------
                        Dollars   kWh's   Capacity  Dispatch       Dollars   kWh's   Capacity   Dispatch
                        -------   -----   --------  --------       -------   ------  --------   --------
Unit 1                 42.9      491.9    94.1%      98.4%          44.3     346.2     66.2%      70.8%
Unit 2                104.8    1,353.3    78.0%      85.2%         115.6   1,483.0     85.4%      89.5%

Unit 1 Electric Revenues (dollars in millions):
-----------------------------------------------

                                                  Three Months Ended                 Nine Months Ended
                                                     September 30,                     September 30,
                                             ------------------------------     ----------------------------
                                                 2002             2001              2002           2001
                                             -------------    -------------     -------------  -------------
Niagara Mohawk                               $     8.3         $    8.9         $    24.7      $    27.8
ISO                                                6.8              6.8              17.9           12.7
PG&E Energy Trading - Power                        0.2              0.3               0.3            3.8
                                             -------------    -------------     -------------  -------------
                                             $    15.3         $   16.0         $    42.9      $    44.3
                                             =============    =============     =============  =============`

The $0.7 million decrease in Unit 1 electric revenues for the three months ended
September 30, 2002 was  primarily  due to lower volumes of delivered  energy and
lower fuel index  pricing in the energy  component  of the Niagara  Mohawk Power
Corporation  (Niagara  Mohawk)  monthly contract  payment.  The $1.4
million decrease in Unit 1 electric revenues for the nine months ended September
30, 2002 was primarily  due to lower fuel index pricing in the energy  component
of the Niagara Mohawk monthly  contract  payment and lower market energy prices,
partially  offset by higher  volumes of  delivered  energy.  The lower volume of
delivered  energy for the nine months ended  September  30, 2001 resulted from a
seven  week  scheduled  maintenance  outage in April and May  2001.  Energy  and
capacity sales to the New York  Independent  System  Operator  (ISO)
were sold at ISO  market  clearing  prices,  and energy  and  capacity  sales to
PG&E Energy Trading   Power,  L.P., an affiliate of JMC Selkirk,  Inc.
(PG&E  Energy Trading - Power),  were sold at negotiated  market
prices.

12

`Unit 2 Electric Revenues (dollars in millions):
-----------------------------------------------

                                                  Three Months Ended                 Nine Months Ended
                                                     September 30,                     September 30,
                                             ------------------------------     ----------------------------
                                                 2002             2001              2002           2001
                                             -------------    -------------     -------------  -------------
Con Edison                                   $    38.3         $   36.8         $   103.6       $  114.5
ISO                                              (0.2)              ---             (0.1)            0.7
PG&E Energy Trading - Power                       ---               ---               1.3            ---
Unrelated third party                             ---               ---               ---            0.4
                                             -------------    -------------     -------------  -------------
                                             $    38.1        $    36.8         $   104.8       $  115.6
                                             =============    =============     =============  =============`

The $1.3 million increase in Unit 2 electric revenues for the three months ended
September 30, 2002 was  primarily  due to escalation in the Con Edison  contract
capacity  payment and higher fuel index pricing in the Con Edison contract price
for delivered energy. The $10.8 million decrease in Unit 2 electric revenues for
the nine months ended  September  30, 2002 was primarily due to lower fuel index
pricing in the Con Edison contract price for delivered  energy and lower volumes
of delivered energy resulting from a four week scheduled  maintenance  outage in
January 2002 and a six week scheduled  maintenance outage in April and May 2002.

Steam  revenues  for the three  and nine  months  ended  September  30,  2002 of
approximately  $0.3  million  and $0.5  million  were  reduced  by a reserve  of
approximately  $0.3 million and $0.4 million,  respectively.  Steam revenues for
the three and nine months ended September 30, 2001 of approximately $0.1 million
and $0.7  million were  reduced by a reserve of  approximately  $0.5 million and
$0.7 million,  respectively.  The Partnership charges General Electric a nominal
price for steam  delivered in an amount up to the annual  equivalent  of 160,000
lbs/hr (the Discounted Quantity). The increase in steam revenues for
the three and nine  months  ended  September  30, 2002 was  primarily  due to an
increase  in  steam  sales in  excess  of the  Discounted  Quantity  to  General
Electric.  Delivered  steam for the three  months ended  September  30, 2002 was
approximately   383.3   million   pounds  or  175,524   lbs/hr  as  compared  to
approximately  292.6  million  pounds or 133,994  lbs/hr  for the  corresponding
period in the prior year.  Delivered  steam for the nine months ended  September
30, 2002 was approximately  1,052.5 million pounds or 161,235 lbs/hr as compared
to approximately  1,053.7 million pounds or 160,818 lbs/hr for the corresponding
period in the prior year.

13

`Fuel Revenues (dollars and MMBtu's in millions):
------------------------------------------------

                                                             For the Three Months Ended
                                              September 30, 2002                     September 30, 2001
                                       ---------------------------------       -------------------------------
                                          Dollars            MMBtu's             Dollars           MMBtu's
                                          -------            -------             -------           -------
Gas Resales                                  0.4                0.1               0.4                0.1
Fuel Optimizations                           4.4                1.4               0.3                0.1
                                       ---------------     -------------       -------------    --------------
                                             4.8                1.5               0.7                0.2
                                       ===============     =============       =============    ==============

                                                             For the Nine Months Ended
                                              September 30, 2002                     September 30, 2001
                                       ---------------------------------       -------------------------------
                                       Dollars                 MMBtu's         Dollars            MMBtu's
                                       -------                 -------         -------            -------
Gas Resales                                  9.1                   2.7              15.2                2.7
Fuel Optimizations                           7.2                   2.3               1.6                0.3
Peak Shaving Arrangements                    0.5                   ---               0.5                ---
                                       ---------------     -------------       -------------    --------------
                                            16.8                   5.0              17.3                3.0
                                       ===============     =============       =============    ==============`

The $4.1 million  increase in fuel revenues for the three months ended September
30,  2002 was  primarily  due to higher  volumes of natural  gas sold under fuel
optimizations.  The $0.5 million  decrease in fuel  revenues for the nine months
ended  September 30, 2002 was primarily due to lower market  natural gas prices,
partially offset by higher volumes of natural gas sold under fuel optimizations.

`Fuel and Transmission Costs (dollars and MMBtu's in millions):
--------------------------------------------------------------

                                                             For the Three Months Ended
                                              September 30, 2002                September 30, 2001
                                       ----------------------------------       ------------------------------
                                          Dollars             MMBtu's             Dollars          MMBtu's
                                          -------             -------             -------          -------
Fuel Supply and
     Transportation*                        24.4                  7.1                 23.7             7.1
Fuel Optimizations                           4.2                  1.4                  0.4             0.1
Transmission Costs                           2.5                  ---                  2.4             ---
                                       ---------------     --------------       ------------    --------------
                                            31.1                  8.5                 26.5             7.2
                                       ===============     ==============       ============    ==============

                                                             For the Nine Months Ended
                                              September 30, 2002                     September 30, 2001
                                       ----------------------------------       ------------------------------
                                          Dollars             MMBtu's             Dollars          MMBtu's
                                          -------             -------             -------          -------
Fuel Supply and
     Transportation*                        69.8                 20.7                 91.2            20.9
Fuel Optimizations                           6.9                  2.3                  1.7             0.3
Transmission Costs                           6.3                  ---                  6.5             ---
                                       ---------------     --------------       ------------    --------------
                                            83.0                 23.0                 99.4            21.2
                                       ===============     ==============       ============    ==============

* Includes the cost of fuel associated with the production of electricity and gas resales.`

14

The $4.6 million  increase in fuel and  transmission  costs for the three months
ended  September  30, 2002 was  primarily  due to higher  volumes of natural gas
purchased  under fuel  optimizations.  The $16.4  million  decrease  in fuel and
transmission  costs for the nine months ended  September  30, 2002 was primarily
due to the lower  price of  natural  gas under the firm fuel  supply  contracts,
partially  offset  by  higher  volumes  of  natural  gas  purchased  under  fuel
optimizations.  The  Partnership  has foreign  currency swap agreements to hedge
against future exchange rate fluctuations under fuel transportation  agreements,
which are  denominated  in Canadian  dollars.  As a result of the currency  swap
agreements,  fuel costs for the three and nine months ended  September  30, 2002
were  increased  by  approximately  $0.8 million and $2.5 million as compared to
approximately $0.8 million and $2.3 million for the corresponding periods in the
prior year.

Unrealized  loss on  derivative  contracts  for the three and nine months  ended
September 30, 2002 was  approximately  $0 and $0.4 million as compared to $0 for
the  corresponding  periods in the prior year. The unrealized  loss reflects the
change in fair value of peak shaving arrangements  recorded in the first quarter
of 2002.

Other  operating  and  maintenance  expenses for the three and nine months ended
September 30, 2002 were approximately $3.0 million and $20.3 million as compared
to approximately $3.7 million and $14.3 million for the corresponding periods in
the prior year.  The $6.0 million  increase for the nine months ended  September
30, 2002 in other  operating  and  maintenance  expenses  were  primarily due to
differences in the scheduling  and scope of planned  maintenance.  The first and
second quarters of 2002 each included a scheduled  maintenance outage on Unit 2,
whereas the second  quarter of 2001 included a scheduled  maintenance  outage on
Unit 1.Liquidity and Capital Resources

Net cash  provided by operating  activities  for the three and nine months ended
September 30, 2002 was approximately $23.0 million and $43.5 million as compared
to approximately  $22.1 million and $46.3 million for the corresponding  periods
in  the  prior  year.  Net  cash  provided  by  operating  activities  primarily
represents net income,  adjusted by non-cash  expenses and income,  plus the net
effect of  changes  within the  Partnership's  operating  assets  and  liability
accounts.

Net cash  provided  by (used  in)  investing  activities  for the three and nine
months ended  September  30, 2002 was  approximately  $14.0  thousand and $(2.1)
million as compared to approximately  $(3.0) thousand and $(909.0)  thousand for
the  corresponding  periods in the prior  year.  Net cash  provided by (used in)
investing activities primarily represents additions to plant and equipment.

15

Net cash  used in  financing  activities  for the three  and nine  months  ended
September 30, 2002 was approximately $23.2 million and $44.5 million as compared
to approximately  $23.0 million and $46.5 million for the corresponding  periods
in the prior year.  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 months ended  September 30, 2002
and 2001 primarily represent deposits of monies into the Interest, Principal and
Debt Service Reserve Funds. Net cash flows used in financing  activities  during
the nine months ended September 30, 2002 and 2001 primarily  represent  deposits
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.

On  October 8, 2002,  Moody's  Investors  Services  ("Moody's")  stated  that in
conjunction with the downgrade of PG&E  National Energy Group, Inc. ("NEG"),
it had placed the  Partnership's  debt under review for possible  downgrade.  On
October  15,  2002,  Standard  and  Poor's  ("S&P")  stated  that the recent
downgrade of NEG will not have an affect on the rating of the Partnership's debt
at this time.  S&P's rating of the Partnership's debt is "BBB-". On November
5, 2002,  Moody's  issued an opinion  update  changing the rating outlook of the
Partnership's  debt to "under review for possible  downgrade"  from "stable" for
the Partnership's  debt due in 2007 and "negative outlook" for the Partnership's
debt due in 2012.  Moody's  rating  of the  Partnership's  debt is  "Baa3".  The
Partnership  is currently  undertaking a review of its  significant  contractual
obligations  in  order  to  assess  the  consequences,  if any,  of a  potential
downgrade of the credit ratings for the Partnership's debt.

The  Partnership  has  available  for its use a  credit  agreement,  as  amended
("Credit  Agreement"),  with a maximum  available credit of  approximately  $7.5
million through August 8, 2003. Outstanding balances bear interest at prime rate
plus .375% per annum with principal and interest payable monthly in arrears. The
Credit  Agreement is available  to the  Partnership  for the purposes of meeting
letters of credit  requirements  under various project contracts and for meeting
working  capital  requirements.  The maximum amount  available  under the Credit
Agreement  for working  capital  purposes is $5.0  million.  As of September 30,
2002,  there were no amounts  drawn or  balances  outstanding  under  either the
letters of credit or the working capital arrangement.

Future operating  results and cash flows from operations are dependent on, among
other things, the performance of equipment;  levels of dispatch;  the receipt of
certain  capacity  and other fixed  payments;  electricity  prices;  natural gas
resale  prices;  fuel  deliveries  and prices;  the  consequences,  if any, of a
potential  downgrade of the credit ratings for the  Partnership's  debt; and the
renewal of the Partnership's  credit agreement.  A significant  change in any of
these factors could have a material  adverse effect on the results of operations
for the Partnership.

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 2002.

16

Market RiskInterest Rates

Interest  rate  risk is the  risk  that  changes  in the  interest  rates  could
adversely  affect  earnings  and  cash  flow.  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,  2002,  if interest  rates  change by 10
percent, the change would be immaterial to the  Partnerships  consolidated
financial statements.

The Partnerships long-term 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 Exchange Rates

Foreign  currency  risk is the risk of  changes  in value of  pending  financial
obligations  in foreign  currencies  that could occur prior to the settlement of
the obligation due to a change in the value of that foreign currency 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, 2002,  a 10 percent  devaluation  of the
Canadian  dollar  would be  immaterial  to the  Partnerships  consolidated
financial statements.Energy Commodity Prices

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 long-term
natural gas 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.

17

Credit Risk

Credit risk is the risk of loss the  Partnership  would incur if  counterparties
were to fail to perform their contractual obligations. 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,  2002,  the  Partnerships  credit risk is  primarily
concentrated with the following customers:  Con Edison,  Niagara Mohawk and ISO,
all of whom are  considered to be of investment  grade.  During the three months
ended September 30, 2002, the parent company of three of the  Partnerships
customers,  all of whom are related parties,  PG&E Energy Trading  Gas
Corporation  (PG&E Energy Trading   Gas),  PG&E Energy
Trading   Canada Corporation and PG&E Energy Trading  Power, was
downgraded below investment grade. The Partnerships net credit exposure to
PG&E Energy Trading   Gas and PG&E Energy Trading   Power at
September   30,  2002  was   approximately   $0.1  million  and  $0.1   million,
respectively.Accounting Principles Issued But Not Yet Adopted

In August 2001,  the Financial  Accounting  Standards  Board  (FASB)
issued       Statement       of      Financial       Accounting       Statements
(SFAS) No. 143,   Accounting  for  Asset  Retirement
Obligations.  This statement is effective for fiscal years beginning after
June 15,  2002. SFAS  No. 143  provides  accounting  requirements  for
obligations associated with the retirement of tangible long-lived assets and the
associated asset  retirement  costs.  Under the statement,  the asset retirement
obligation  is  recorded  at fair value in the period in which it is incurred by
increasing the carrying amount of the related long-lived asset. The liability is
accreted to its present value in each subsequent period and the capitalized cost
is  depreciated  over the useful life of the related asset.  The  Partnership is
currently  evaluating  the  impact  of  SFAS  No. 143  on its  consolidated
financial statements.

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements
No.  4,  44,  and  64,  Amendment  of  FASB  Statement  No.  13,  and  Technical
Corrections.  This statement eliminates the current requirement that gains
and losses on debt  extinguishment  must be classified as extraordinary items in
the income  statement.  Instead,  such gains and losses  will be  classified  as
extraordinary  items only if they are deemed to be unusual  and  infrequent,  in
accordance with the current GAAP criteria for extraordinary  classification.  In
addition,  SFAS 145 eliminates an inconsistency in lease accounting by requiring
that  modifications  of  capital  leases  that  result  in  reclassification  as
operating  leases be accounted for  consistent  with  sale-leaseback  accounting
rules.  The  statement  also contains  other 46  nonsubstantive  corrections  to
authoritative accounting literature.  The changes related to debt extinguishment
will be effective for fiscal years beginning after May 15, 2002, and the changes
related to lease accounting will be effective for  transactions  occurring after
May 15,  2002.  The  Partnership  does not expect  that  implementation  of this
statement  will  have  a  significant  impact  on  its  consolidated   financial
statements.

18
In June  2002,  the  FASB  issued  SFAS  No.  146,  Accounting  for  Costs
Associated with Exit or Disposal  Activities,  which addresses  accounting
for restructuring and similar costs. SFAS No. 146 supersedes previous accounting
guidance,  principally Emerging Issues Task Force  (EITF)  Issue No.
94-3.  This  statement  is to be  applied  prospectively  to  exit  or  disposal
activities  initiated  after  December 31, 2002.  SFAS No. 146 requires that the
liability for costs  associated with an exit or disposal  activity be recognized
when the  liability  is incurred.  Under EITF No. 94-3, a liability  for an exit
cost was recognized at the date of a companys  commitment to an exit plan.
SFAS No. 146 also  establishes  that the liability  should initially be measured
and recorded at fair value. The Partnership does not expect that  implementation
of this statement will have a significant  impact on its consolidated  financial
statements.Critical Accounting Policies

Effective January 1, 2001, the Partnership  adopted SFAS No. 133. This statement
requires  the  Partnership  to  recognize  all  derivatives,  as  defined in the
statement, on the consolidated balance sheets at fair value.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, 2001 Annual Report on Form
10-K for further discussion of significant pending litigation.
19
Regulations and Environmental Matters

On November 6, 2001, the Partnership received from the New York State Department
of Environmental  Conservation (the 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.  The DEC has  confirmed  that the  terms and
conditions of the Title V Permit are stayed  pending a final DEC decision on the
appeal.  Since November 12, 2001, the  Partnership and DEC staff have engaged in
negotiations  regarding the Title V Permit. 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.
20
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.)
21
ITEM 4.   CONTROLS AND PROCEDURESEvaluation of Disclosure Controls and Procedures

Based  on an  evaluation  of  the  Partnerships  disclosure  controls  and
procedures  conducted on October 21, 2002, 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 SECs
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.
22
PART II. OTHER INFORMATIONITEM 6.   EXHIBITS AND REPORTS ON FORM 8-K
(A)      Exhibits

         Exhibit No.       Description
         -----------       -----------

         10.5.16           First  Amending  Agreement  dated as of the 1st day of November
                           2002, to the Second Amended and Restated Gas Purchase Contract
                           dated as of May 6, 1998 between Paramount Resources Ltd. and
                           Selkirk Cogen Partners, L.P.

         99.9              Certification of P. Chrisman Iribe pursuant to 18 U.S.C. Section
                           1350 dated November 14, 2002.

         99.10             Certification of John R. Cooper pursuant to 18 U.S.C. Section
                           1350 dated November 14, 2002.

         99.11             Certification of P. Chrisman Iribe pursuant to 18 U.S.C. Section
                           1350 dated November 14, 2002.

         99.12             Certification of John R. Cooper pursuant to 18 U.S.C. Section
                           1350 dated November 14, 2002.


(B)      Reports on Form 8-K

         Not applicable.
Omitted  from this Part II are items  which are not  applicable  or to which the
answer is negative for the periods covered.
23
SIGNATURES
Pursuant to the  requirements of Section 13 or 15(d) of the Securities  Exchange
Act of 1934,  the  Registrant  has duly  caused  this report to be signed on its
behalf by the undersigned thereunto duly authorized.
SELKIRK COGEN PARTNERS, L.P.

                                            By:   JMC SELKIRK, INC.
                                                   Managing General Partner

Date: November 14, 2002                     /s/ JOHN R. COOPER
                                            -------------------------------------
                                            Name:   John R. Cooper
                                            Title:  Senior Vice President,
                                                    Chief Financial Officer and
                                                    Treasurer
24
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 FUNDING
                                            CORPORATION

Date:  November 14, 2002                    /s/  JOHN R. COOPER
                                            ------------------------------------
                                            Name:  John R. Cooper
                                            Title: Senior Vice President,
                                                   Chief Financial Officer and
                                                   Treasurer
25

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


I, P. Chrisman Iribe, certify that:

1.   I have  reviewed  this  quarterly  report  on Form  10-Q of  Selkirk  Cogen
     Partners, L.P.;

2.   Based on my knowledge,  this  quarterly  report does not contain any untrue
     statement of a material fact or omit to state a material fact  necessary to
     make the statements  made, in light of the  circumstances  under which such
     statements  were made, not misleading with respect to the period covered by
     this quarterly report;

3    Based on my  knowledge,  the  financial  statements,  and  other  financial
     information  included  in this  quarterly  report,  fairly  present  in all
     material respects the financial  condition,  results of operations and cash
     flows of the  registrant  as of, and for,  the  periods  presented  in this
     quarterly report;

4.   The  registrants  other certifying officers and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

          a)   designed such  disclosure  controls and procedures to ensure that
               material  information  relating to the registrant,  including its
               consolidated  subsidiaries,  is made known to us by others within
               those  entities,  particularly  during  the  period in which this
               quarterly report is being prepared;

          b)   evaluated the effectiveness of the  registrants  disclosure
               controls and  procedures  within 90 days prior to the filing date
               of  this  quarterly  report  (the  Evaluation  Date);
               and

          c)   presented  in this  quarterly  report our  conclusions  about the
               effectiveness of the disclosure  controls and procedures based on
               our evaluation as of the Evaluation Date;

5.   The registrants other certifying officers and I have disclosed, based
     on our most recent evaluation,  to the  registrants  auditors and the
     audit  committee  of  registrants  board  of  directors  (or  persons
     performing the equivalent function):

          a)   all  significant  deficiencies  in the  design  or  operation  of
               internal    controls   which   could    adversely    affect   the
               registrants  ability  to  record,  process,  summarize  and
               report    financial   data   and   have    identified   for   the
               registrants  auditors any material  weaknesses  in internal
               controls; and

          b)   any fraud,  whether or not material,  that involves management or
               other employees who have a significant  role in the  registrant's
               internal controls; and

6.   The  registrants  other  certifying  officers and I have indicated in
     this  quarterly  report  whether or not there were  significant  changes in
     internal  controls  or in other  factors  that could  significantly  affect
     internal  controls  subsequent  to the date of our most recent  evaluation,
     including any corrective  actions with regard to  significant  deficiencies
     and material weaknesses.



Date: November 14, 2002              /s/ P. CHRISMAN IRIBE
                                     ---------------------
                                     P. Chrisman Iribe
                                     President
                                     JMC Selkirk, Inc.
                                     Managing General Partner of Selkirk Cogen
                                     Partners, L.P.

                                       26


CERTIFICATION OF JOHN R. COOPER, PRINCIPAL FINANCIAL OFFICER,
         PURSUANT TO SECTION 302 OF THE SARBINES-OXLEY ACT OF 2002

I, John R. Cooper, certify that:

1.   I have  reviewed  this  quarterly  report  on Form  10-Q of  Selkirk  Cogen
     Partners, L.P.;

2.   Based on my knowledge,  this  quarterly  report does not contain any untrue
     statement of a material fact or omit to state a material fact  necessary to
     make the statements  made, in light of the  circumstances  under which such
     statements  were made, not misleading with respect to the period covered by
     this quarterly report;

3.   Based on my  knowledge,  the  financial  statements,  and  other  financial
     information  included  in this  quarterly  report,  fairly  present  in all
     material respects the financial  condition,  results of operations and cash
     flows of the  registrant  as of, and for,  the  periods  presented  in this
     quarterly report;

4.   The  registrants  other certifying officers and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in  Exchange  Act  Rules  13a-14  and  15d-14)  for the  registrant  and we
     have:

     a)   designed  such  disclosure  controls  and  procedures  to ensure  that
          material  information  relating  to  the  registrant,   including  its
          consolidated subsidiaries,  is made known to us by others within those
          entities,  particularly  during  the  period in which  this  quarterly
          report is being prepared;

     b)   evaluated  the  effectiveness  of  the  registrants   disclosure
          controls  and  procedures  within 90 days prior to the filing  date of
          this  quarterly   report  (the   Evaluation   Date);   and

     c)   presented  in  this  quarterly   report  our  conclusions   about  the
          effectiveness  of the disclosure  controls and procedures based on our
          evaluation as of the Evaluation Date;

5.   The registrants other certifying officers and I have disclosed, based
     on our most recent evaluation,  to the  registrants  auditors and the
     audit  committee  of  registrants  board  of  directors  (or  persons
     performing the equivalent function):

     a)   all  significant  deficiencies  in the design or operation of internal
          controls which could adversely affect the registrants ability to
          record,  process,   summarize  and  report  financial  data  and  have
          identified for the registrants  auditors any material weaknesses
          in internal controls; and

     b)   any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          controls; and

6.   The  registrants  other  certifying  officers and I have indicated in
     this  quarterly  report  whether or not there were  significant  changes in
     internal  controls  or in other  factors  that could  significantly  affect
     internal  controls  subsequent  to the date of our most recent  evaluation,
     including any corrective  actions with regard to  significant  deficiencies
     and material weaknesses.

Date: November 14, 2002

                                    /s/ JOHN R. COOPER
                                    -------------------------------------------
                                    John R. Cooper
                                    Senior Vice President, Chief Financial Officer
                                    and Treasurer
                                    JMC Selkirk, Inc.
                                    Managing General Partner of Selkirk Cogen
                                    Partners, L.P.


                                       27

CERTIFICATION OF p. CHRISMAN IRIBE, PRINICPAL EXECUTIVE OFFICER,
           PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, P. Chrisman Iribe, certify that:

1.   I have reviewed this quarterly report on Form 10-Q of Selkirk Cogen Funding
     Corporation;

2.   Based on my knowledge,  this  quarterly  report does not contain any untrue
     statement of a material fact or omit to state a material fact  necessary to
     make the statements  made, in light of the  circumstances  under which such
     statements  were made, not misleading with respect to the period covered by
     this quarterly report;

3.   Based on my  knowledge,  the  financial  statements,  and  other  financial
     information  included  in this  quarterly  report,  fairly  present  in all
     material respects the financial  condition,  results of operations and cash
     flows of the  registrant  as of, and for,  the  periods  presented  in this
     quarterly report;

4.   The  registrants  other certifying officers and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in  Exchange  Act  Rules  13a-14  and  15d-14)  for the  registrant  and we
     have:

     a)   designed  such  disclosure  controls  and  procedures  to ensure  that
          material  information  relating  to  the  registrant,   including  its
          consolidated subsidiaries,  is made known to us by others within those
          entities,  particularly  during  the  period in which  this  quarterly
          report is being prepared;

     b)   evaluated  the  effectiveness  of  the  registrants   disclosure
          controls  and  procedures  within 90 days prior to the filing  date of
          this  quarterly   report  (the   Evaluation   Date);   and

     c)   presented  in  this  quarterly   report  our  conclusions   about  the
          effectiveness  of the disclosure  controls and procedures based on our
          evaluation as of the Evaluation Date;

5.   The registrants other certifying officers and I have disclosed, based
     on our most recent evaluation,  to the  registrants  auditors and the
     audit  committee  of  registrants  board  of  directors  (or  persons
     performing the equivalent function):

     a)   all  significant  deficiencies  in the design or operation of internal
          controls which could adversely affect the registrants ability to
          record,  process,   summarize  and  report  financial  data  and  have
          identified for the registrants  auditors any material weaknesses
          in internal controls; and

     b)   any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          controls; and

6.   The  registrants  other  certifying  officers and I have indicated in
     this  quarterly  report  whether or not there were  significant  changes in
     internal  controls  or in other  factors  that could  significantly  affect
     internal  controls  subsequent  to the date of our most recent  evaluation,
     including any corrective  actions with regard to  significant  deficiencies
     and material weaknesse.


Date: November 14, 2002


                                              /s/ P. CHRISMAN IRIBE
                                              ---------------------------------
                                              P. Chrisman Iribe
                                              President
                                              Selkirk Cogen Funding Corporation

                                       28
CERTIFICATION OF JOHN R. COOPER, PRINCIPAL FINANCIAL OFFICER,
         PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John R. Cooper, certify that:

1.   I have reviewed this quarterly report on Form 10-Q of Selkirk Cogen Funding
     Corporation;

2.   Based on my knowledge,  this  quarterly  report does not contain any untrue
     statement of a material fact or omit to state a material fact  necessary to
     make the statements  made, in light of the  circumstances  under which such
     statements  were made, not misleading with respect to the period covered by
     this quarterly report;

3.   Based on my  knowledge,  the  financial  statements,  and  other  financial
     information  included  in this  quarterly  report,  fairly  present  in all
     material respects the financial  condition,  results of operations and cash
     flows of the  registrant  as of, and for,  the  periods  presented  in this
     quarterly report;

4.   The  registrants  other certifying officers and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in  Exchange  Act  Rules  13a-14  and  15d-14)  for the  registrant  and we
     have:

     a)   designed  such  disclosure  controls  and  procedures  to ensure  that
          material  information  relating  to  the  registrant,   including  its
          consolidated subsidiaries,  is made known to us by others within those
          entities,  particularly  during  the  period in which  this  quarterly
          report is being prepared;

     b)   evaluated  the  effectiveness  of  the  registrants   disclosure
          controls  and  procedures  within 90 days prior to the filing  date of
          this  quarterly   report  (the   Evaluation   Date);   and

     c)   presented  in  this  quarterly   report  our  conclusions   about  the
          effectiveness  of the disclosure  controls and procedures based on our
          evaluation as of the Evaluation Date;

     5.   The registrants  other certifying officers and I have disclosed,
          based on our most recent evaluation, to the registrants auditors
          and the audit  committee of  registrants  board of directors (or
          persons performing the equivalent function):

          a)   all  significant  deficiencies  in the  design  or  operation  of
               internal    controls   which   could    adversely    affect   the
               registrants  ability  to  record,  process,  summarize  and
               report    financial   data   and   have    identified   for   the
               registrants  auditors any material  weaknesses  in internal
               controls; and

          b)   any fraud,  whether or not material,  that involves management or
               other employees who have a significant  role in the  registrant's
               internal controls; and

6.   The  registrants  other  certifying  officers and I have indicated in
     this  quarterly  report  whether or not there were  significant  changes in
     internal  controls  or in other  factors  that could  significantly  affect
     internal  controls  subsequent  to the date of our most recent  evaluation,
     including any corrective  actions with regard to  significant  deficiencies
     and material weaknesses.

Date: November 14, 2002


                             /s/ JOHN R. COOPER
                             --------------------------------------------------
                             John R. Cooper
                             Senior Vice President, Chief Financial Officer and
                             Treasurer
                             Selkirk Cogen Funding Corporation




                                       29