`=====================================================================================================`

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 June 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 August  12,  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 June 30, 2002
           and December 31, 2001.......................................      1

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

           Consolidated Statements of Cash Flows for the three and six
           months ended June 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.......................................     10

           Liquidity and Capital Resources.............................     14

Item 3.    Quantitative and Qualitative Disclosures About Market Risk..     18


                        PART II. OTHER INFORMATION

Item 6.    Exhibits and Reports on Form 8-K............................    19

SIGNATURES.............................................................    20


                                       i`

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

`June 30,         December 31,
                                                                                2002               2001
                                                                           ---------------    ---------------
ASSETS

CURRENT ASSETS:
    Cash and cash equivalents                                                   $   1,594          $   4,546
    Restricted funds                                                                8,562              7,699
    Accounts receivable, net of allowance of $0 and $32, respectively              18,142             17,789
    Due from affiliates                                                               996              1,127
    Fuel inventory and supplies                                                     5,921             10,228
    Other current assets                                                            1,298                511
    Asset for derivative contracts                                                    ---                446
                                                                           ---------------    ---------------
               Total current assets                                                36,513             42,346
                                                                           ---------------    ---------------

PLANT AND EQUIPMENT:
    Plant and equipment, at cost                                                  374,944            373,476
    Less: Accumulated depreciation                                                105,657             99,563
                                                                           ---------------    ---------------
               Plant and equipment, net                                           269,287            273,913
                                                                           ---------------    ---------------
LONG-TERM RESTRICTED FUNDS                                                         26,854             24,314

DEFERRED FINANCING CHARGES, net of accumulated
     amortization of $9,445 and $8,901, respectively                                6,846              7,390
                                                                           ---------------    ---------------
TOTAL ASSETS                                                                   $  339,500         $  347,963
                                                                           ===============    ===============

LIABILITIES AND PARTNERS' DEFICITS

CURRENT LIABILITIES:
    Accounts payable                                                             $    368         $    1,729
    Accrued bond interest payable                                                     351                357
    Accrued fuel expenses                                                           9,667              8,689
    Accrued property taxes                                                          3,200              2,296
    Accrued operating and maintenance expenses                                      3,574              1,262
    Other accrued expenses                                                          3,483              4,173
    Due to affiliates                                                               1,109              2,008
    Current portion of long-term bonds                                             15,406             13,529
    Current portion of liability for derivative contracts                           2,571              3,688
                                                                           ---------------    ---------------
               Total current liabilities                                           39,729             37,731

LONG-TERM LIABILITIES:
    Deferred revenue                                                                4,243              4,597
    Other long-term liabilities                                                     6,881              7,070
    Long-term bonds - net of current portion                                      340,737            349,235
    Liability for derivative contracts - net of current
    portion                                                                         3,137              5,113
                                                                           ---------------    ---------------
               Total liabilities                                                  394,727            403,746
                                                                           ---------------    ---------------

COMMITMENTS AND CONTINGENCIES

PARTNERS' DEFICITS:
    General partners' deficits                                                      (487)              (458)
    Limited partners' deficits                                                   (49,032)           (46,524)
    Accumulated other comprehensive loss                                          (5,708)            (8,801)
                                                                           ---------------    ---------------
               Total partners' deficits                                          (55,227)           (55,783)
                                                                           ---------------    ---------------
TOTAL LIABILITIES AND PARTNERS' DEFICITS                                       $  339,500         $  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 Six Months Ended
                                                        --------------------------------     ------------------------------

                                                           June 30,         June 30,           June 30,         June 30,
                                                             2002             2001               2002             2001
                                                        ---------------   --------------     --------------   -------------
OPERATING REVENUES:
     Electric and steam                                     $   44,931       $   45,927          $  94,394       $ 107,511
     Fuel revenues                                               8,493           11,750             11,985          16,639
                                                                                             --------------   -------------
                                                        ---------------   --------------
              Total operating revenues                          53,424           57,677            106,379         124,150
                                                        ---------------   --------------     --------------   -------------

COST OF REVENUES:
     Fuel and transmission costs                                27,784           32,401             51,939          72,855
     Unrealized loss on derivative contracts                       ---              ---                446             ---
     Other operating and maintenance                            10,770            7,197             17,301          10,537
     Depreciation                                                3,139            3,124              6,260           6,238
                                                        ---------------   --------------     --------------   -------------
              Total cost of revenues                            41,693           42,722             75,946          89,630
                                                        ---------------   --------------     --------------   -------------
GROSS PROFIT                                                    11,731           14,955             30,433          34,520
                                                        ---------------   --------------     --------------   -------------

OTHER OPERATING EXPENSES:
     Administrative services, affiliates                           187              539                701             970
     Other general and administrative                              804              677              1,461           1,282
     Amortization of deferred financing charges                    272              280                544             560
                                                        ---------------   --------------     --------------   -------------
              Total other operating expenses                     1,263            1,496              2,706           2,812
                                                        ---------------   --------------     --------------   -------------

OPERATING INCOME                                                10,468           13,459             27,727          31,708
                                                        ---------------   --------------     --------------   -------------

INTEREST (INCOME) EXPENSE:
     Interest income                                             (260)            (667)              (467)         (1,305)
     Interest expense                                            8,026            8,266             16,058          16,537
                                                        ---------------   --------------     --------------   -------------
              Total interest expense, net                        7,766            7,599             15,591          15,232
                                                        ---------------   --------------     --------------   -------------

NET INCOME                                                   $   2,702        $   5,860         $   12,136       $  16,476
                                                        ===============   ==============     ==============   =============

NET INCOME ALLOCATION:
     General partners                                         $     28         $     59           $    122        $    165
     Limited partners                                            2,674            5,801             12,014          16,311
                                                        ---------------   --------------     --------------   -------------
     TOTAL                                                   $   2,702        $   5,860           $ 12,136        $ 16,476
                                                        ===============   ==============     ==============   =============

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 Six Months Ended
                                                                 -----------------------------   -------------------------

                                                                   June 30,        June 30,       June 30,      June 30,
                                                                     2002            2001           2002          2001
                                                                 -------------    ------------   -----------   -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
     Net income                                                      $  2,702         $ 5,860       $12,136      $ 16,476
     Adjustments to reconcile net income to net cash
        provided by operating activities:
        Depreciation and amortization                                   3,411           3,404         6,804         6,798
        Unrealized loss on derivative contracts                           ---             ---           446           ---
        Deferred revenue                                                (177)           (177)         (354)         (354)
        Loss on disposal of plant and equipment                           481              32           481            32
        Increase (decrease) in cash resulting from a change
        in:
           Restricted funds                                           (1,321)           3,353       (3,402)           892
           Accounts receivable                                          (597)             922         (353)         1,958
           Due from affiliates                                          (604)           1,660           131         3,235
           Fuel inventory and supplies                                  2,585         (1,860)         4,307       (2,033)
           Other current assets                                         (889)           (911)         (787)         (820)
           Accounts payable                                               187           (137)       (1,361)          (49)
           Accrued bond interest payable                              (8,038)         (8,277)           (6)           (6)
           Accrued fuel expenses                                          646         (1,565)           978       (4,667)
           Accrued property taxes                                         ---             ---           904           100
           Accrued operating and maintenance expenses                   2,401             138         2,312         (276)
           Other accrued expenses                                     (1,389)             443         (690)         1,270
           Due to affiliates                                              312           1,645         (899)         1,673
           Other long-term liabilities                                    730             731         (189)          (89)
                                                                 -------------    ------------   -----------   -----------
            Net cash provided by operating activities                     440           5,261        20,458        24,140
                                                                 -------------    ------------   -----------   -----------

CASH FLOWS FROM INVESTING ACTIVITIES:
     Plant and equipment additions                                    (1,949)           (650)       (2,115)         (916)
     Proceeds from disposal of plant and equipment                        ---              10           ---            10
                                                                 -------------    ------------   -----------   -----------
            Net cash used in investing activities                     (1,949)           (640)       (2,115)         (906)
                                                                 -------------    ------------   -----------   -----------

CASH FLOWS FROM FINANCING ACTIVITIES:
     Restricted funds                                                  22,597          20,103           (1)           ---
     Distributions to partners                                       (14,673)        (17,545)      (14,673)      (17,545)
     Repayment of long-term debt                                      (6,621)         (6,010)       (6,621)       (6,010)
                                                                 -------------    ------------   -----------   -----------
            Net cash provided by (used in) financing                    1,303         (3,452)      (21,295)      (23,555)
            activities
                                                                 -------------    ------------   -----------   -----------

NET INCREASE (DECREASE) IN CASH AND
    CASH EQUIVALENTS                                                    (206)           1,169       (2,952)         (321)
                                                                 -------------    ------------   -----------   -----------

CASH AND CASH EQUIVALENTS,
    BEGINNING OF PERIOD                                                 1,800           1,697         4,546         3,187
                                                                 -------------    ------------   -----------   -----------

CASH AND CASH EQUIVALENTS,
    END OF PERIOD                                                    $  1,594        $  2,866       $ 1,594       $ 2,866
                                                                 =============    ============   ===========   ===========
SUPPLEMENTAL CASH FLOW INFORMATION:
      Cash paid for interest                                         $ 16,064        $ 16,543       $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 six
months  ended June 30, 2001 to conform with the current  periods  basis of
presentation. Operating results for the three and six months ended June 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 six months ended June 30, 2002 and 2001 (in millions):

`Three Months Ended                 Six Months Ended
                                                        June 30,                         June 30,
                                                 2002             2001              2002           2001
                                             -------------    -------------     -------------  -------------
Net income                                        $   2.7          $   5.9          $   12.1        $  16.5
Cumulative effect of adoption of
   SFAS No. 133                                       ---              ---               ---          (9.0)
Net gain (loss) from current period
   hedging transactions in accordance
   with SFAS No. 133                                  1.4              0.7               1.4          (1.1)

Net reclassification to earnings                      0.8              0.7               1.7            1.5
                                             -------------    -------------     -------------  -------------
Comprehensive income                              $   4.9          $   7.3          $   15.2         $  7.9
                                             =============    =============     =============  =============`

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  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 six months  ended June 30, 2002 and 2001,  expenses  incurred  for  services
provided  by JMCS I  Management  totaled  approximately  $0.7  million  and $1.0
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 JMCS I Management
for these services at June 30, 2002, was approximately $0.3 million.

6

The Partnership  purchases and sells gas to PG&E  Energy Trading   Gas
Corporation,  Pittsfield Generating Company,  L.P. and MASSPOWER,  affiliates of
JMC Selkirk,  Inc., at fair value. Gas purchased from affiliates of JMC Selkirk,
Inc. for the six months ended June 30, 2002 and 2001, totaled approximately $3.5
million  and  $4.0  million  respectively,  and gas  sold to  affiliates  of JMC
Selkirk,   Inc.   totaled   approximately   $11.5   million  and  $14.7  million
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  affiliates  of JMC  Selkirk,  Inc.  for
purchases of gas at June 30, 2002 was  approximately  $0.8 million and the total
amount due from  affiliates  of JMC  Selkirk,  Inc. for sales of gas at June 30,
2002 was approximately $1.0 million.

In May 1996, the  Partnership  entered into an enabling  agreement with PG&E
Energy  Trading    Power,  L.P.,  an affiliate of JMC  Selkirk,  Inc.,  to
purchase and sell electric capacity, electric energy, and other electric-related
products.  For the six months  ended June 30,  2002 and 2001,  sales to PG&E
Energy Trading   Power, L.P. totaled  approximately  $1.4 million and $3.5
million, respectively.  Sales to PG&E Energy Trading  Power, L.P. were
recorded as electric  revenues in the  accompanying  consolidated  statements of
operations. The total amount due from PG&E Energy Trading  Power, L.P.
at June 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 six months  ended June 30,
2002, firm fuel  transportation  services from IGTS totaled  approximately  $3.7
million and $3.8  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 June 30, 2002, was approximately $0.7
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 June 30, 2002 and 2001,  amounts charged to
fuel  costs  as a  result  of  losses  realized  from  these  contracts  totaled
approximately  $0.8 million and $0.7 million,  respectively.  For the six months
ended  June 30,  2002 and 2001,  amounts  charged  to fuel  costs as a result of
losses realized from these contracts totaled approximately $1.7 million and $1.5
million,  respectively.  The Partnership  expects that net derivative  losses of
approximately $2.6 million,  included in accumulated other comprehensive loss as
of June 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 six months
ended June 30, 2002 and 2001 (in millions):

`Three Months Ended                 Six Months Ended
                                                        June 30,                         June 30,
                                                 2002             2001              2002           2001
                                             -------------    -------------     -------------  -------------
Beginning accumulated other comprehensive        $  (7.9)        $  (10.0)          $  (8.8)       $  (9.0)
    loss at April 1 and January 1,
    respectively
Net gain (loss) from current period hedging
    transactions                                      1.4              0.7               1.4          (1.1)
Net reclassification to earnings                      0.8              0.7               1.7            1.5
                                             -------------    -------------     -------------  -------------

Ending accumulated other comprehensive loss      $  (5.7)         $  (8.6)          $  (5.7)       $  (8.6)
                                             =============    =============     =============  =============`

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.

As  of  June  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.

Note 5. Bankruptcy of Affiliated 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").

8

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.  Subsequent to the bankruptcy  filing,  the investment
grade  ratings of NEG were  reaffirmed on April 6 and 9, 2001. On July 31, 2002,
S&P  downgraded NEG to BB+ with CreditWatch with negative  implications from
BBB with a stable outlook. On August 5, 2002, Moodys downgraded NEG to Ba2
from Baa2 and maintained its negative  rating  outlook.  Neither agency took any
ratings  action  with  respect  to the  rating of the  Partnerships  debt.

The Managing  General Partner believes that the credit rating agency action will
have no impact on the  financial  condition  or  results  of  operations  of the
Partnership. In addition, 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.

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, it is too early for the
Partnership to 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.

9

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 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 Six Months Ended June 30, 2002 Compared to the Three and Six Months
Ended June 30, 2001

The Partnership  earned net income of  approximately  $2.7 million for the three
months  ended June 30, 2002 as compared to  approximately  $5.9  million for the
corresponding  period in the prior year.  The  Partnership  earned net income of
approximately  $12.1  million for the six months ended June 30, 2002 as compared
to approximately  $16.5 million for the corresponding  period in the prior year.
The $3.2 million and $4.4 million  decreases in net income for the three and six
months  ended June 30,  2002,  respectively  were  primarily  due to lower gross
profit  resulting  from  differences  in the  scheduling  and  scope of  planned
maintenance.

Total  operating  revenues for the three and six months ended June 30, 2002 were
approximately  $53.4  million and $106.4  million as  compared to  approximately
$57.7  million  and $124.1  million for the  corresponding  periods in the prior
year.

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


                                            For the Three Months Ended
                                   June 30, 2002                                  June 30, 2001
                        -----------------------------------------    ----------------------------------------
                        Dollars   kWh's   Capacity  Dispatch         Dollars    kWh's     Capacity   Dispatch
                        -------   -----   --------  --------         -------    ------    --------   --------
Unit 1                   12.7      159.9    91.7%      95.2%          10.4      84.8     48.6%      51.5%
Unit 2                   32.3      325.0    56.2%      57.8%          35.7     391.1     67.6%      73.3%`

10

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

                                                     For the Six Months Ended
                                   June 30, 2002                             June 30, 2001
                        -------------------------------------      -------------------------------------
                        Dollars   kWh's   Capacity   Dispatch      Dollars   kWh's   Capacity   Dispatch
                        -------   -----   --------   --------      -------   ------  --------   --------
Unit 1                   27.6      338.4    97.8%      97.6%         28.3     187.8     54.1%      56.0%
Unit 2                   66.8      777.9    67.6%      77.7%         78.7     909.8     79.0%      84.2%


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

                                                  Three Months Ended                 Six Months Ended
                                                        June 30,                         June 30,
                                             ------------------------------     ----------------------------
                                                 2002             2001              2002           2001
                                             -------------    -------------     -------------  -------------
Niagara Mohawk                                    $   6.5          $   6.6           $  16.4        $  19.0
ISO                                                   6.1              3.6              11.1            5.8
PG&E Energy Trading                                   0.1              0.2               0.1            3.5
                                             -------------    -------------     -------------  -------------
                                                  $  12.7          $  10.4           $  27.6        $  28.3
                                             =============    =============     =============  =============`

The $2.3 million increase in Unit 1 electric revenues for the three months ended
June 30, 2002 was primarily due to higher volumes of delivered energy, partially
offset by lower market energy prices.  The lower volume of delivered  energy for
the three  months  ended June 30,  2001  resulted  from a seven  week  scheduled
maintenance  outage.  The $0.7 million decrease in Unit 1 electric  revenues for
the six months ended June 30, 2002 was primarily due to lower fuel index pricing
in the energy component of the Niagara Mohawk Power  Corporation  (Niagara
Mohawk) monthly contract payment and lower market energy prices, partially
offset by higher volumes of delivered  energy.  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), were sold at negotiated market prices.

`Unit 2 Electric Revenues (dollars in millions):

                                                  Three Months Ended                 Six Months Ended
                                                        June 30,                         June 30,
                                             ------------------------------     ----------------------------
                                                 2002             2001              2002           2001
                                             -------------    -------------     -------------  -------------
Con Edison                                        $  32.3         $   34.6           $  65.4        $  77.6
ISO                                                   ---              0.7               0.1            0.7
PG&E Energy Trading                                   ---              ---               1.3            ---
Unrelated third party                                 ---              0.4               ---            0.4
                                             -------------    -------------     -------------  -------------
                                                  $  32.3          $  35.7           $  66.8        $  78.7
                                             =============    =============     =============  =============`

11

The $3.4  million and $11.9  million  decreases in Unit 2 electric for the three
and six months ended June 30, 2002,  respectively  were  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 six months ended June 30, 2002 of approximately
$0 and $0.2 million were reduced by a reserve of approximately  $0.1 million and
$0.2 million,  respectively.  Steam  revenues for the three and six months ended
June 30, 2001 of  approximately $0 and $0.6 million were reduced by a reserve of
approximately $0.2 million.  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 decrease in steam revenues for
the three and six months ended June 30, 2002 was  primarily due to a decrease in
steam sales in excess of the Discounted Quantity to General Electric.  Delivered
steam for the three months ended June 30, 2002 was  approximately  301.5 million
pounds or 138,048  lbs/hr as compared to  approximately  328.2 million pounds or
150,267 lbs/hr for the corresponding  period in the prior year.  Delivered steam
for the six months ended June 30, 2002 was approximately 669.2 million pounds or
154,051  lbs/hr as compared to  approximately  761.0  million  pounds or 174,229
lbs/hr for the corresponding period in the prior year.

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

                                                             For the Three Months Ended
                                                June 30, 2002                          June 30, 2001
                                       ---------------------------------       -------------------------------
                                          Dollars            MMBtu's             Dollars           MMBtu's
                                          -------            -------             -------           -------
Gas Resales                                  7.2               2.0                11.3                2.0
Fuel Optimizations                           1.3               0.3                 0.4                0.1
Peak Shaving Arrangements                    ---               ---                 ---                ---
                                       ---------------     -------------       -------------    --------------
                                             8.5               2.3                11.7                2.1
                                       ===============     =============       =============    ==============

                                                              For the Six Months Ended
                                                June 30, 2002                          June 30, 2001
                                       ---------------------------------       -------------------------------
                                       Dollars                 MMBtu's         Dollars            MMBtu's
                                       -------                 -------         -------            -------

Gas Resales                                  8.7                2.6              14.8                2.6
Fuel Optimizations                           2.8                0.9               1.3                0.2
Peak Shaving Arrangements                    0.5                ---               0.5                ---
                                       ---------------     -------------       -------------    --------------
                                            12.0                3.5              16.6                2.8
                                       ===============     =============       =============    ==============`

The $3.2 million and $4.6 million  decreases in fuel  revenues for the three and
six months ended June 30, 2002,  respectively were primarily due to lower market
natural gas prices, partially offset by higher volumes of natural gas sold under
fuel optimizations.

12

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

                                                             For the Three Months Ended
                                                 June 30, 2002                          June 30, 2001
                                       ----------------------------------       ------------------------------
                                          Dollars             MMBtu's             Dollars          MMBtu's
                                          -------             -------             -------          -------
Fuel Supply and
     Transportation*                        24.6                  6.9                 29.8             6.8
Fuel Optimizations                           1.2                  0.3                  0.4             0.1
Transmission Costs                           1.9                  ---                  2.2             ---
                                       ---------------     --------------       ------------    --------------
                                            27.7                  7.2                 32.4             6.9
                                       ===============     ==============       ============    ==============


                                                              For the Six Months Ended
                                                 June 30, 2002                          June 30, 2001
                                       ----------------------------------       ------------------------------
                                       Dollars              MMBtu's              Dollars         MMBtu's
                                       -------              -------              -------         -------
Fuel Supply and
     Transportation*                        45.4              13.6                 67.5            13.8
Fuel Optimizations                           2.7               0.9                  1.3             0.2
Transmission Costs                           3.8               ---                  4.1             ---
                                       ---------------     --------------       ------------    --------------
                                            51.9              14.5                 72.9            14.0
                                       ===============     ==============       ============    ==============`

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

The $4.7 million and $21.0 million decreases in fuel and transmission  costs for
the three and six months ended June 30, 2002, respectively were primarily due to
the  lower  price of  natural  gas under the firm  fuel  supply  contracts.  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 six months  ended June 30, 2002 were  increased  by
approximately  $0.8 million and $1.7 million as compared to  approximately  $0.7
million  and $1.5  million  for the  corresponding  periods  in the prior  year.

Unrealized loss on derivative  contracts for the three and six months ended June
30,  2002 was  approximately  zero and $0.4  million as compared to zero 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 six months ended June
30,  2002 were  approximately  $10.8  million  and $17.3  million as compared to
approximately  $7.2 million and $10.5 million for the  corresponding  periods in
the prior year. The $3.6 million and $6.8 million  increases in other  operating
and  maintenance  expenses  for the three and six months  ended  June 30,  2002,
respectively,  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.

13

Liquidity and Capital Resources

Net cash  provided by  operating  activities  for the three and six months ended
June 30, 2002 was  approximately  $0.4 million and $20.5  million as compared to
approximately  $5.3 million and $24.1 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 used in  investing  activities  for the three and six months ended June
30,  2002 was  approximately  $1.9  million  and $2.1  million  as  compared  to
approximately $0.6 million and $0.9 million for the corresponding periods in the
prior year. Net cash used in investing activities primarily represents additions
to plant and equipment.

Net cash provided by (used in) financing activities for the three and six months
ended June 30,  2002 was  approximately  $1.3  million  and  $(21.3)  million as
compared  to   approximately   $(3.5)  million  and  $(23.6)   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  provided by (used in)  financing  activities  during the
three  and  six  months  ended  June  30,  2002  and  2001  primarily  represent
distributions to partners and the semi-annual  payment of principal and interest
on long-term debt.

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;  and fuel deliveries and prices.  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.Market RiskInterest Rates

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.  A 10% decrease in interest rates for the three and six
months  ended  June 30,  2002  would  have  resulted  in a  negative  impact  of
approximately  $26.0 thousand and $46.7 thousand on the  Partnerships  net
income.

14

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

The  Partnerships  currency swap agreements  hedge against future exchange
rate  fluctuations  which could result in additional  costs  incurred under fuel
transportation  agreements which are denominated in a foreign  currency.  In the
event  a  counterparty   fails  to  meet  the  terms  of  the  agreements,   the
Partnerships   exposure  is  limited  to  the   currency   exchange   rate
differential.  During the three and six months ended June 30, 2002, the currency
exchange rate differential  resulted in a negative impact of approximately  $0.8
million and $1.7 million on the Partnerships net income.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.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  June  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.

15

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.

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.

16

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.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, it is too early for the
Partnership to 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.

17

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.)

18

PART II.   OTHER INFORMATION

ITEM 6.    EXHIBITS AND REPORTS ON FORM 8-K

`(A)          Exhibits

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

         10.6.20           Firm Transportation Negotiated Rate Letter Agreement, dated as of
                           June 18, 2002, between Tennessee Gas Pipeline Company and
                           Selkirk Cogen Partners, L.P.

         10.6.21           Agreement under FT-a Rate Schedule, dated as of June 19, 2002,
                           between Tennessee Gas Pipeline Company and Selkirk Cogen
                           Partners, L.P.

         10.6.22           Gas  Transportation  Agreement,  dated as of August 1, 2002,
                           between  Tennessee  Gas  Pipeline  Company and Selkirk Cogen
                           Partners, L.P.

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

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

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

         99.8              Certification of John R. Cooper pursuant to 18 U.S.C. Section
                           1350 dated August 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.

19

SIGNATURES

Pursuant to the  requirements of Section 13 or 15(d) of the Securities  Exchange
Act of 1934,  the  Registrant  has duly  caused  this report to be signed on its
behalf by the undersigned thereunto duly authorized.

`SELKIRK COGEN PARTNERS, L.P.

                                          By:   JMC SELKIRK, INC.
                                                Managing General Partner

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

20

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

21