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                                UNITED STATES
                     SECURITIES AND EXCHANGE COMMISSION
                            WASHINGTON, DC  20549

                                  FORM 10-Q

            [X]		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
                      OF THE SECURITIES EXCHANGE ACT OF 1934
                     For the quarterly period ended March 31, 1998
                                   
                       Commission 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             (IRS Employer
      incorporation or organization)             Identification No.)
      
          
                      SELKIRK COGEN FUNDING CORPORATION
           (Exact name of Registrant as specified in its charter)

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

               One Bowdoin Square, Boston, Massachusetts 02114
        (Address of principal executive offices, including zip code)

                               (617) 227-8080
            (Registrant's telephone number, including area code)

         SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
                8.65% First Mortgage Bonds Due 2007, Series A
                8.98% First Mortgage Bonds Due 2012, Series A
                              (Title of class)


	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 May 15, 1998, there were 10 shares of common stock of Selkirk Cogen
Funding Corporation, $1 par value outstanding.

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             This document consists of 20 pages of which this page is page 1.

<PAGE>






                                                  








                              TABLE OF CONTENTS




										                                Page
																		----
                       PART I.  FINANCIAL INFORMATION


Item 1.	Financial Statements (unaudited)

		Condensed Consolidated Balance Sheets as of March 31, 1998 
		and December 31, 1997.........................................	   3

		Condensed Consolidated Statements of Operations for the three 
		months ended March 31, 1998 and March 31, 1997................	   4

		Condensed Consolidated Statements of Cash Flows for the three 
		months ended March 31, 1998 and March 31, 1997................	   5

		Notes to Condensed Consolidated Financial Statements..........	   6

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

		Results of Operations.........................................	   7


		Liquidity and Capital Resources...............................	   9


                         PART II.  OTHER INFORMATION


Item 6.		Exhibits and Reports on Form 8-K..........................	  18

SIGNATURES............................................................	  19







                                     2
<PAGE>


                        
<TABLE>
                        SELKIRK COGEN PARTNERS, L.P.
                    CONDENSED CONSOLIDATED BALANCE SHEETS
                               (in thousands)
                                
<CAPTION>							
                                                   (unaudited)
				   					     			March 31,   December 31, 
						                        	  1998		    1997
												   ----------	------------
<S>													  <C>			<C>
ASSETS		
										
Current assets:									
  Cash............................................ $    4,781     $    1,337 
  Restricted funds................................	   17,431          6,509 
  Accounts receivable.............................     15,608         17,764 
  Due from affiliates.............................         14             14 
  Fuel inventory and supplies.....................	    5,066          4,936
  Other current assets............................	      235	         338 
  													---------	   ---------
    	Total current assets......................	   43,135         30,898 
										
  Plant and equipment, net........................    318,371        321,537 
  Long-term restricted funds......................     22,689         21,494 
  Deferred financing charges, net.................     11,654         11,945 
							  						---------	   ---------

				Total Assets		 	 	       $  395,849      $ 385,874
   													---------	   ---------
													---------	   ---------
LIABILITIES AND PARTNERS' CAPITAL									
										
Current liabilities:									
  Accounts payable................................ $     --- 	  $    1,663 
  Accrued bond interest payable...................	    8,987 	         382 
  Accrued expenses................................     11,752         14,665 
  Due to affiliates...............................        476 	         498 
  Current portion of long-term bonds..............      3,298 	       3,298 
	  												---------	   ---------
	    Total current liabilities.................	   24,513         20,506 
										
  Other long-term liabilities.....................	   13,942         11,695 
  Long-term bonds, less current portion...........	  385,955        385,955
										
  General partners' capital.......................	     (274) 		    (311) 
  Limited partners' capital.......................    (28,287)       (31,971)
	   												---------	   ---------
	    Total partners' capital...................    (28,561)       (32,282) 
													---------	   ---------

				Total Liabilities and
					 Partners' Capital             $  395,849     $  385,874 
													---------	   ---------
													---------	   ---------
<FN>
See Notes to Condensed Consolidated Financial Statements.									
</TABLE>
                                     3
<PAGE>
				 																							
<TABLE>
                        SELKIRK COGEN PARTNERS, L.P.
               CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
                               (in thousands)
                                 (unaudited)
											
											
											
<CAPTION>																						
							  					  For the Three Months Ended			
												  --------------------------

					 			    			   	March 31,	   March 31,	
													  1998	      	 1997	
												   ----------	  ----------
<S>                                                    <C>            <C>
Operating revenues:								   

    Electric and steam............................ $   39,418     $   42,521 	
	Gas resale....................................	    1,991 	       1,404
													---------	   ---------
	    Total operating revenues..................	   41,409         43,925 	
Cost of revenue...................................     28,108         31,291
													---------	   ---------
Gross Profit......................................	   13,301         12,634 	
						 	 	   			
Other operating expenses:										
	Administrative services - affiliates..........	      587 		     609 	
	Other general and administrative expenses.....	      544 		     737 	
	Amortization of deferred financing charges....	      291 		     293 	
						     						---------	   ---------
		Total other operating expenses............	    1,422          1,639 	
													---------	   ---------

Operating income..................................	   11,879         10,995 	
											
Net interest expense..............................	    8,157          8,151 	
													---------	   ---------
Net income........................................ $    3,722     $    2,844 	
												    ---------	   ---------
													---------	   ---------

Allocated to:										
	General partners.............................. $       37 	  $       29 	
	Limited partners..............................	    3,685 	       2,815 	
                                                    ---------	   ---------
		Total..................................... $    3,722 	  $    2,844 	
												    ---------	   ---------
													---------	   ---------
<FN>
See Notes to Condensed Consolidated Financial Statements.										
</TABLE>
																						
                                     4
<PAGE>




<TABLE>
                        SELKIRK COGEN PARTNERS, L.P.
               CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
                               (in thousands)
                                 (unaudited)
												
<CAPTION>												
												  For the Three Months Ended			
												  --------------------------

					 			    			   	March 31,	   March 31,	
													  1998	      	 1997	
							                       ----------	  ----------												
														
<S>                                                    <C>			  <C>									
Net cash provided by operating activities......... $   15,561     $   14,282	
												
Cash flows provided by (used in)
 investing activities:											
	Plant and equipment additions.................      ---  	          34
	Restricted funds..............................    (12,117)		 (16,099)
												    ---------	   ---------

		Net cash used in investing activities.....	  (12,117)       (16,065) 	
												
Cash flows used in financing activities:											
	Advances from a customer......................      ---	             (17) 	
								  					---------	   ---------

		Net cash used in financing activities.....	    ---            	 (17)
																		 
Net decrease in cash..............................      3,444		  (1,800)	
Cash at beginning of period.......................      1,337          2,591 	
													---------	   ---------
Cash at end of period.............................  $   4,781 	  $      791
									 				---------	   ---------
													---------	   ---------

Supplemental disclosures of cash flow information:										

	Cash paid for interest........................  $   ---       $       17   
													---------	   ---------
													---------	   ---------

<FN>
See Notes to Condensed Consolidated Financial Statements.										
</TABLE>											
											
																				
                                     5
<PAGE>



                        SELKIRK COGEN PARTNERS, L.P.

            NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
                                 (unaudited)

Note 1. Basis of Presentation


The  accompanying  unaudited   condensed  consolidated  financial  statements
consolidate 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 condensed  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.  The information
furnished in the  condensed  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
information  and  footnote   disclosures   normally   included  in  financial
statements  prepared  in  accordance  with  generally   accepted   accounting
principles  have  been condensed or omitted pursuant to rules and regulations
applicable to interim  financial  statements.  Certain reclassifications have
been made to the Condensed Consolidated  Statements  of  Operations  for  the
three  months ended March 31, 1997 to conform with the current period's basis
of presentation.

These  condensed  consolidated  financial   statements   should  be  read  in
conjunction with the audited consolidated financial  statements  included  in
the Partnership's December 31, 1997 Annual Report on Form 10-K.

                                     6
<PAGE>


  ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
  ------------------------------------------------------------------------

  RESULTS OF OPERATIONS
  ---------------------

Results of Operations

Three Months Ended March 31, 1998 Compared to the Three Months Ended
March 31, 1997

Net income for  the  quarter  ended  March  31,  1998  was approximately $3.7
million as compared to $2.8 million for the corresponding period in the prior
year.  The $0.9 million increase in net income is primarily  due  to  a  $0.6
million  increase in gas resale revenues and a $0.2 million decrease in other
general and administrative expenses.

Total revenues for the quarter ended  March 31, 1998 were approximately $41.4
million as compared to $43.9 million for  the  corresponding  period  in  the
prior year.

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

							    For the Three Months Ended	
      				    March 31, 1998               March 31, 1997	
			  ------------------------------- -------------------------------
			  Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
			  ------- ----- -------- -------- ------- -----	-------- --------	 
Niagara Mohawk    8.3 102.6   59.43%   64.44%	 10.0 161.1   90.31% 100.00%	   
Con Edison	     31.1 519.4   90.75%   93.94%    32.4 485.9	  84.88%  98.56%    


Revenues from Niagara  Mohawk  Power  Corporation  ("Niagara Mohawk") for the
quarter ended March 31, 1998 decreased approximately $1.7 million as compared
to the corresponding period in the  prior  year.   A  decrease  in  delivered
energy  as  evidenced  by  the decrease in the capacity factor from 90.31% to
59.43% was the primary contributor  to  the decrease in revenues.  During the
quarter ended March 31, 1998, Niagara Mohawk dispatched Unit 1 on-line during
January and February and off-line during March.  Energy delivered during  the
majority  of  January  and  the  entire  month  of  February was sold at full
contract rates.  Energy delivered during  the  first four days in January was
sold under special dispatch arrangements which  called  for  the  pricing  of
delivered  energy  at  variable rates less than full contract rates.  Had the
Partnership not entered  into  the  special  dispatch  arrangements, the Unit
would have otherwise been dispatched  off-line.   During  the  quarter  ended
March  31,  1997,  Niagara  Mohawk  dispatched  Unit 1 on-line and all of the
energy delivered was sold  under  special  dispatch arrangements which called
for the pricing of delivered energy at variable rates less than full contract
rates.   Revenues  for  energy  delivered  pursuant   to   special   dispatch
arrangements  with  Niagara  Mohawk for the quarter ended March 31, 1998 were
approximately $0.2 million as compared  to $4.8 million for the corresponding
period in the prior year.

                                     7

<PAGE>
Revenues from Consolidated Edison Company of New York,  Inc.  ("Con  Edison")
for  the quarter ended March 31, 1998 decreased approximately $1.3 million as
compared to the  corresponding  period  in  the  prior  year.   A decrease in
contract energy rates resulting from lower index fuel prices was only  partly
offset  by  an  increase in delivered energy (as evidenced by the increase in
the capacity factor  from  84.88%  to  90.75%)  and  was the principal factor
contributing to the decrease in revenues.

Pursuant to the Steam Sales Agreement, General Electric is charged a  nominal
amount  which is the annual equivalent of 160,000 lbs/hr.  During the quarter
ended March 31, 1998, steam revenues  were reduced to zero because the annual
equivalent was not exceeded and an annual true-up of $0.2 million in favor of
General Electric was recorded.  During the quarter ended March 31, 1997 steam
revenues were approximately $0.1 million, which includes an annual true-up of
$0.9 million in favor of General Electric.  The decrease  in  steam  revenues
during  the  quarter  ended  March  31, 1998 was primarily due to lower steam
demand.  During the quarter ended  March 31, 1998 approximately 385.9 million
pounds of steam were delivered as compared  to  approximately  506.3  million
pounds for the corresponding period in the prior year.

Gas  resale  revenues for the quarter ended March 31, 1998 were approximately
$2.0 million on sales  of  approximately  0.9  million MMBtu's as compared to
$1.4  million  on  sales  of  approximately  0.5  million  MMBtu's  for   the
corresponding  period in the prior year.  The increase in gas resale revenues
was primarily due to lower  dispatch  of  Unit  1 offset by lower natural gas
resale prices, which resulted in  higher  volumes  of  natural  gas  becoming
available  for  resale  at  lower prices.  The decrease in natural gas resale
prices during the quarter ended  March  31, 1998 generally resulted from more
moderate temperatures in the Northeast  region  as  compared  to  the  colder
temperatures,  which  caused an increase in the demand for natural gas during
the corresponding period in the prior  year.  The Partnership enters into gas
resales during periods when Units 1 and 2 are not operating at full capacity.

Cost of revenues for the quarter ended  March  31,  1998  were  approximately
$28.1  million  on  purchases  of  6.9  million  MMBtu's as compared to $31.3
million on purchases of 6.9  million  MMBtu's for the corresponding period in
the prior year.  The largest component of the decrease for the quarter  ended
March  31,  1998  was fuel costs, which decreased $3.2 million from the prior
year.  The decrease in the cost  of  fuel  was primarily due to a decrease in
contract firm fuel rates from lower index  fuel  prices  and  rate  decreases
under  the firm transportation contracts.  During the quarter ended March 31,
1998, firm fuel purchases from suppliers were comparable to the corresponding
period in the prior year.

Total other operating  expenses  for  the  quarter  ended  March 31, 1998 was
approximately $1.4 million as compared to $1.6 million for the  corresponding
period  in  the  prior  year.   The  decrease  in other operating expenses is
primarily due to a decrease in other general and administrative expenses.

                                  
                                     8

<PAGE>

Net  interest  expense  for the quarter ended March 31, 1998 of approximately
$8.2 million was comparable to the corresponding period in the prior year.


Liquidity and Capital Resources

Net cash flows provided by  operating activities increased from approximately
$14.3 million for the quarter ended March 31, 1997 to $15.6 million  for  the
quarter  ended  March  31,  1998.  The increase in net cash flows provided by
operating activities is  primarily  due  to  the  increase  in net income and
normally recurring changes in cash  receipts  and  disbursements  within  the
Partnership's operating asset and liability accounts during the quarter ended
March 31, 1998.

Net  cash  flows used in investing activities for the quarter ended March 31,
1998 was approximately $12.1  million  as  compared  to $16.1 million for the
corresponding period in the prior year.  Net cash  flows  used  in  investing
activities  primarily  represent monies deposited into funds created pursuant
to the Partnership's Depositary  and  Disbursement Agreement, administered by
Bankers Trust Company, as depositary agent (the "Funds").   Monies  deposited
into  the  Funds  during the quarter ended March 31, 1998 primarily represent
monies set aside for interest payments  to Bondholders scheduled for June 26,
1998.  Monies deposited into the Funds during the  quarter  ended  March  31,
1997 primarily represent monies set aside for interest and principal payments
to Bondholders scheduled for June 26, 1997.

There were no net cash flows associated with financing activities during  the
quarter  ended  March  31, 1998.  Net cash flows used in financing activities
for the quarter  ended  March  31,  1997  of  $17,000  represent a payment to
General Electric pursuant to the Steam Sales Agreement.


The Partnership has entered into a Master Restructuring Agreement (as amended
on March 31, 1998, April 21, 1998, April 30, 1998 and May 7, 1998, the "MRA")
dated July 9, 1997 among  Niagara  Mohawk,  the Partnership and certain other
non-utility power generators  selling  electricity  to  Niagara  Mohawk  (the
"Settling IPP's").  For a description of certain applicable provisions of the
MRA  and  related  transactions  see "Unit 1 Restructuring" below.  On May 7,
1998, the  Partnership,  together  with  other  Settling  IPP's,  agreed with
Niagara Mohawk that certain third party conditions to the obligations of  the
Settling  IPP's under the MRA have been either satisfied or waived, excluding
the  receipt  of  certain  regulatory  approvals  and,  in  the  case  of the
Partnership, the satisfaction of certain standards and procedures  under  the
Partnership's   Trust   Indenture   for   consummation  of  the  transactions
contemplated by the MRA.  If  the  Partnership  and Niagara Mohawk proceed to
complete the transactions provided under the MRA,  which  completion  remains
subject to a number of significant contingencies, the existing Niagara Mohawk
Power Purchase Agreement will be amended and restated to modify the basis on

                                     9

<PAGE>



which  the  Partnership  makes sales of the electrical capacity and output of
Unit 1 (the "Amended  and  Restated  Unit  1  Agreement").  Management of the
Partnership believes that, based on those facts and  circumstances  currently
known,  and  certain  assumptions which management believes to be reasonable,
proceeding with the Amended and Restated  Unit 1 Agreement is not expected to
have a material adverse impact on the Partnership's future operating  results
and cash flows from operations.  Should this conclusion change for any reason
prior  to completion of the MRA transactions, the Partnership does not expect
that it would  be  able  to  satisfy  the  standards  set  forth in its Trust
Indenture and would, therefore, not be obligated to proceed further under the
MRA.  For the quarter ended March 31, 1998,  capacity  and  energy  sales  to
Niagara Mohawk accounted for approximately 20.0% of total project revenues.

Con  Edison by a letter dated September 19, 1994 claimed the right to acquire
that portion of Unit 2's firm  natural  gas supply not used in operating Unit
2, when Unit 2 is dispatched off-line or at less than full  capability.   The
Con Edison Power Purchase Agreement contains no express language granting Con
Edison any rights with respect to such excess natural gas.  Nevertheless, Con
Edison  has argued that, since payments under the contract include fixed fuel
charges which are payable whether  or  not  Unit 2 is dispatched on-line, Con
Edison is  entitled  to  take  delivery  of  any  excess  natural  gas.   The
Partnership  vigorously  disputes  the  position adopted by Con Edison, based
notably on the absence of any  contractual provision according Con Edison the
claimed rights but also on the fact that the Partnership has assumed the risk
under the Con Edison Power Purchase Agreement that the fuel  charges  payable
by  Con  Edison  are insufficient to cover the costs actually incurred by the
Partnership.  By a  letter  dated  May  23,  1995,  Con  Edison indicated its
intention to pursue the claim asserted in the September 19, 1994 letter.   In
the  May  23, 1995 letter, Con Edison reserved the right to claim 100% of the
margins derived from the sales of  Unit  2's firm natural gas supply not used
in operating Unit 2 (non-plant gas sales) and requested that the  Partnership
reduce the monthly amount invoiced to Con Edison by 50% of a calculated value
of  the  non-plant  gas  sales.   The Partnership strenuously objected to Con
Edison's contentions  and,  at  a  meeting  between  the  Partnership and Con
Edison, Con Edison agreed to continue not to deduct any  amount  attributable
to non-plant gas sales from payments made upon monthly invoices but stated it
would  do  so under protest, pending further discussions between the parties.
Since the commencement of  commercial  operations  of Unit 2, the Partnership
made and continues to make, from time to time, excess gas lay-off sales  from
Unit  2's  gas supply.  The Partnership does not intend to adjust the monthly
invoices  issued to Con Edison and continues to assert that Con Edison is not
entitled to any revenues or margins derived from non-plant gas sales.  In the
event Con Edison were  to  pursue  its  asserted claim, the Partnership would
expect to pursue all available legal remedies, but there can be no  certainty
that  the  outcome  of  such  remedial  action  would  be  favorable  to  the
Partnership  or,  if  favorable,  would  provide  for  the Partnership's full
recovery of its damages.

                                     10

<PAGE>

The Partnership's cash  flows  from  the  sale  of  electric  output would be
materially and adversely affected if Con Edison were to prevail in its  claim
to Unit 2's excess natural gas volumes and the related margins.

Future  operating  results  and  cash flows from operations are dependent on,
among other things, the performance  of  equipment and processes as expected,
level of dispatch, fuel deliveries and price as contracted and the receipt of
certain capacity and other fixed payments.  A significant change  in  any  of
these  factors  could  have  a material adverse effect on the results for the
Partnership.

The Partnership believes that  based  on current conditions and circumstances
it will have sufficient liquidity  available  provided  by  cash  flows  from
operations to fund existing debt obligations and operating costs.


Unit 1 Restructuring 

In  October  1995,  Niagara Mohawk filed its "Power Choice" proposal with the
New York State Public  Service  Commission  ("NYPSC").   On October 12, 1995,
Niagara Mohawk filed a Report on Form 8-K with the  Securities  and  Exchange
Commission   explaining   the   Power  Choice  proposal  (the  "Power  Choice
Statement").  In  the  Power  Choice  Statement,  Niagara  Mohawk described a
number of related proposals to restructure the utility's business,  including
the  reorganization of its assets and the renegotiation of its contracts with
generators which,  like  the  Partnership,  are  not  regulated  as utilities
("non-utility generators").  The  Power  Choice  Statement  proposed  several
alternative  ways  to  restructure  agreements  with  non-utility generators,
including the exercise by Niagara  Mohawk  of  the power of eminent domain to
take  possession  of  the  projects  of  non-utility  generators  with   whom
negotiations  were  unsuccessful.   Following  the filing of the Power Choice
proposal with the NYPSC,  the  Partnership  joined with other non-utility gen
erators selling power to Niagara Mohawk to commence negotiations concerning a
joint settlement that would result in the  termination  or  restructuring  of
their respective power purchase agreements.

On  July  9,  1997,  Niagara  Mohawk,  the Partnership and the Settling IPP's
representing,  in  the  aggregate,  twenty-nine  power  purchase  agreements,
entered into the MRA.  On  October  11,  1997, Niagara Mohawk filed its Power
Choice settlement, which incorporates the terms of the MRA, with  the  NYPSC.
On  February  24,  1998,  the  NYPSC  approved  Niagara Mohawk's Power Choice
settlement proposal, including the implementation of the MRA.

                                     11

<PAGE>

Master  Restructuring  Agreement.   The  MRA,  if  consummated,  includes the
following principal features:  (i) Niagara Mohawk will pay to those  Settling
IPP's  terminating their respective power purchase agreements (which does not
include the Partnership) a combination of cash payments and shares of Niagara
Mohawk Common Stock, (ii) certain of the power purchase agreements (including
the existing Niagara Mohawk  Power  Purchase  Agreement with the Partnership)
will be amended and restated, such  that  the  Settling  IPP's  rights  on  a
going-forward  basis  will include the right to receive (or the obligation to
pay) indexed electric rate swap  payments  and  the  right to "put" a defined
quantity  of  electricity  to  Niagara  Mohawk  until  a  power  exchange  is
established in Niagara Mohawk's service territory,  and  (iii)  substantially
all  of  the  Settling  IPP's  (including  the  Partnership) will receive, as
compensation for certain estimated  costs  identified  in connection with the
restructuring of their gas supply and transportation arrangements  (the  "gas
mitigation  costs"),  cash payments derived from certain fixed price electric
rate swap contracts to be  entered  into  by  Niagara Mohawk with one or more
counterparties,   or   alternatively,   directly   from    Niagara    Mohawk.
Implementation  of  the MRA is subject to a number of significant conditions,
certain of which have  not  yet  been satisfied, including without limitation
the  receipt  of  all  regulatory  approvals,  the  satisfaction  of  certain
standards under the Partnership's Trust Indenture relating to the absence  of
material adverse changes or receiving any required approval of bondholders or
other creditors, and the receipt by Niagara Mohawk of all necessary approvals
from its board of directors and shareholders.

On May 7, 1998, pursuant to the MRA, the  Partnership  delivered  to  Niagara
Mohawk  written  notice  that, with certain exceptions, the conditions to the
Partnership's obligations under the  MRA  which  involve the consent of third
parties (other than regulatory approvals) and the  modification  of  existing
contractual arrangements with third parties had been either satisfied or were
being  waived  by the Partnership.  The specified exceptions, satisfaction of
which continue to be conditions  to the Partnership's obligation to undertake
the transactions contemplated by the MRA, include (i) receipt of the approval
of  the  Partnership's  bondholders  to  the  Unit  1  restructuring   or   a
determination   by  the  Partnership  that  it  will  undertake  the  Unit  1
restructuring  without  a  vote  of  its  bondholders  as  permitted  by  the
Partnership's Trust Indenture (the  "Indenture  Approval")  and (ii) upon the
request of the Partnership, mutually satisfactory  renegotiation  of  certain
provisions  of  the  proposed  Amended  and  Restated  Unit 1 Agreement to be
entered into by Niagara Mohawk and the Partnership relating to the dependable
maximum net capability ("DMNC") of  Unit 1 (described below).  Should Niagara
Mohawk and the Partnership satisfy all of the conditions to effectuating  the
transactions contemplated by the MRA with respect to the Partnership, Niagara
Mohawk  may nevertheless terminate the MRA if Niagara Mohawk determines that,
as a result of the  failure  to  satisfy  the  conditions of the MRA by other
independent power producers, the  benefits  anticipated  to  be  received  by
Niagara  Mohawk  pursuant  to  the  MRA  have  been  materially and adversely
affected.  Further,  final  implementation  of  the  MRA  is conditioned upon
Niagara Mohawk's successful completion of financing required to fund  certain
of  its  payment obligations under agreements to implement the MRA.  Although
the MRA establishes June 30,  1998  as  the closing date for the transactions
with the other Settling IPP's (the "IPP Closing"),

                                     12

<PAGE>

pursuant to an amendment to the MRA, the Partnership may extend the time  for
securing  the  Indenture  Approval and closing the MRA transactions as to the
Partnership  (the  "Selkirk  Closing"  )  until  August  31,  1998.   If  the
Partnership has not obtained  the  Indenture  Approval  by such date, the MRA
will terminate as to the Partnership.

Unless the MRA has been terminated as to the Partnership on or before the IPP
Closing, on such date the Partnership  will  be  obligated  to  fund  certain
payments related to the agreed allocation among the Settling IPP's of certain
costs  and  benefits  under  the  MRA and the allocated gas mitigation costs.
Currently, the Partnership  estimates  that  these  payments  will total $2.2
million.  If the MRA  is  subsequently  terminated  as  to  the  Partnership,
Niagara  Mohawk  is  contractually obligated to reimburse the Partnership for
this amount within two  business  days  of  such termination.  If the Selkirk
Closing is consummated, the Partnership will be entitled to receive,  as  its
net  share  of  the agreed allocation among IPP's for certain adjustments and
gas mitigation costs,  a  cash  payment  currently  estimated  to total $10.4
million (representing net receipts to the Partnership of  approximately  $8.2
million).

Amended  and Restated Unit 1 Agreement.  Following the execution and delivery
of the MRA, the Partnership  and  Niagara Mohawk commenced negotiation of the
Amended and Restated Unit 1 Agreement.  In accordance with the terms  of  the
MRA,  the  format  for  the  negotiated Amended and Restated Unit 1 Agreement
consists of an indexed electric rate ISDA swap contract (the "Swap Contract")
and  a  power  put  agreement   (the   "Put  Contract")  which  are  intended
collectively to  amend  and  restate  the  existing  Unit  1  Power  Purchase
Agreement  with  Niagara  Mohawk.   The  Partnership  and Niagara Mohawk have
reached definitive agreement on the  detailed  terms of the Swap Contract and
the Put Contract, but the effectiveness of these agreements is subject to the
closing of the  MRA  transactions  as  to  the  Partnership.   The  following
discussion  is  intended  to present only the broad outlines of the principal
terms included in the  current  version  of  the  Amended and Restated Unit 1
Agreement.

The  Swap  Contract  portion  of  the  Amended  and Restated Unit 1 Agreement
involves only cash  payment  obligations  and  does  not require the physical
production or delivery of Unit 1 electrical capacity or output.   During  the
ten-year  term of the Swap Contract, one party will be required to pay to the
other party, on a monthly  basis,  the  difference between the Fixed Payments
and the Floating Payments (each defined below) for such month.  If the  Fixed
Payments exceed the Floating Payments, Niagara Mohawk will pay the difference
to  the Partnership.  If the Floating Payments exceed the Fixed Payments, the
Partnership  will  pay  the  difference  to  Niagara  Mohawk.   These payment
obligations are determined solely on the  basis  of  the  factors  referenced
below and will not be affected by whether Unit 1 is operated.

                                     13

<PAGE>

The Fixed Payment and the Floating Payment are each calculated on  the  basis
of  a  notional  contract  quantity,  expressed in megawatts ("MW"), which is
established at  37  MW  in  the  first  contract  year,  escalating in annual
increments to 55 MW in the tenth  contract  year.   The  "Fixed  Payment"  is
determined  by  multiplying  the  applicable  monthly contract quantity by an
indexed contract price (the "Contract  Price").   The Contract Price is fixed
for the first contract year and the second contract year  and  thereafter  is
determined  by  the  application  of  a  formula  which  takes into account a
specified heat rate, changes  in  a  consumer  price  index and a gas pricing
component based on the Canadian spot  gas  price  at  Empress,  Alberta  (the
"Empress  spot  price").   The  Contract  Price  has been designed to reflect
generally the Partnership's principal cost  components for Unit 1 operations.
The Fixed Payment is subject to downward adjustment if at any time during the
term of the Swap Contract the tested DMNC of Unit 1 falls below the  notional
contract quantity (the "DMNC Adjustment").

The  "Floating  Payment"  is determined by multiplying the applicable monthly
contract quantity  by  a  market  price  that  will  initially  equal Niagara
Mohawk's short term avoided energy and capacity costs as stated in its tariff
for power purchases from "qualifying facilities" within the  meaning  of  the
Public Utility Regulatory Policies Act of 1978, as amended (the "Proxy-Market
Price").   At  such time as an independent system operator and power exchange
within New York ("ISO/power exchange")  is established and fully functioning,
the market price used in determining the Floating Payment will equal the  day
ahead  locational based market price published by the ISO/power exchange (the
"Market Price"), unless the parties agree to continue to use the Proxy-Market
Price.  The Floating Payment, like the  Fixed Payment, is subject to the DMNC
Adjustment.  After the establishment of the ISO/power exchange, and only if a
separate market for capacity is established by  ISO/power  exchange  capacity
auctions,  the  Floating Payment is subject to increase by an amount equal to
the market price paid to sellers  of electrical capacity at the Partnership's
delivery point (the "Market Capacity  Price"),  multiplied  by  the  weighted
average capacity associated with the notional contract quantity.

The  Put  Contract portion of the Amended and Restated Unit 1 Agreement, like
the Swap Contract, has a term of  ten  years.  The central feature of the Put
Contract, however, which is the ability of the Partnership to require Niagara
Mohawk to purchase energy, terminates at the time the ISO/power  exchange  is
established  and fully functioning.  Upon prior notice to Niagara Mohawk, the
Partnership may put  energy  and  associated  capacity  to Niagara Mohawk for
periods ranging from one hour to one month, up to 105% of the then applicable
monthly contract quantity (which parallels the Swap  Contract).   The  energy
and  capacity put to Niagara Mohawk under the Put Contract may be produced by
Unit 1, Unit 2 or any other  source.   The price to be paid by Niagara Mohawk
for energy and associated capacity purchased by it upon the exercise  of  the
Partnership's  put option will be the Proxy-Market Price or the Market Price,
and, if applicable, the Market Capacity Price.

                                     14

<PAGE>

If the Partnership  elects  not  to  exercise  its  option  to put energy and
associated capacity to Niagara Mohawk, it may sell such energy  and  capacity
to third parties, but only if the Partnership first offers Niagara Mohawk the
opportunity to purchase such energy and capacity at the Proxy-Market Price or
the  Market Price, and, if applicable, the Market Capacity Price, and Niagara
Mohawk declines.  The Partnership has the right to sell energy and associated
capacity of Unit 1 in excess  of  the applicable monthly contract quantity to
third parties without giving Niagara Mohawk a right of first refusal.

If and when the Swap Contract and Put Contract go into effect, Niagara Mohawk
will  cease  to  have  the  right  to  direct  dispatch  of  Unit  1, and the
Partnership's decision as to whether,  and  at  what  capacity, to run Unit 1
will be largely based on market conditions then in effect.   The  market  and
pricing  risks  associated  with  such  operation during the first ten years,
however, will be mitigated by the payment obligations of Niagara Mohawk under
the  Swap  Contract.   The  Partnership's  existing  Unit  1  interconnection
agreement with Niagara Mohawk will  remain  in force and effect following the
Unit 1 restructuring,  as  will  the  existing  Unit  2  interconnection  and
transmission agreements with Niagara Mohawk.

Unit 1 Gas Supply and Transportation.  Following the execution  of  the  MRA,
the  Partnership  commenced  negotiations  with  its  Unit  1  gas  supplier,
Paramount  Resources  Ltd.  ("Paramount"), to effect certain modifications to
the existing Unit 1 Gas  Purchase  Contract with Paramount necessary to align
the principal terms of the Unit 1 gas supply with the  proposed  Amended  and
Restated  Unit  1  Agreement.   On May 6, 1998, the Partnership and Paramount
executed a Second Amended  and  Restated  Gas Purchase Contract (the "Amended
Paramount Contract"), which will take effect on the later  to  occur  of  the
date  Paramount and the Partnership obtain any necessary regulatory approvals
for the amendment and  the  date  of  the  Selkirk  Closing,  when the Unit 1
restructuring under the MRA is consummated.

Under  the  Amended  Paramount  Contract, the following key volume, price and
dedicated reserve terms (among others) would be modified as follows:  (i) the
maximum daily quantity of natural  gas  which  the Partnership is entitled to
purchase would be reduced from 23,000 Mcf to 16,400 Mcf; (ii)  the  commodity
charge  component  of  the  contract  price  would  cease  to be a base price
escalated with Niagara Mohawk's fossil  fuel  index but would instead reflect
the current Empress spot  price  (the  same  indexed  price  as  is  used  to
determine  the  Contract Price under the Swap Contract portion of the Amended
and Restated Unit 1 Agreement); (iii) the gas price renegotiation/arbitration
provisions in  the  existing  Paramount  Contract  would  be eliminated; (iv)
Paramount would have increased flexibility to manage the  reserves  dedicated
to  the  Amended  Paramount  Contract  so  long  as  Paramount is meeting its
delivery obligations for the volumes nominated by the Partnership; and (v) on
any day  on  which  Paramount  fails  to  meet  its  delivery obligations for
Partnership  nominations,  Paramount  would  be   obligated   to   make   its
transportation on NOVA Corporation of Alberta available to the Partnership to
the extent of the shortfall.

                                     15

<PAGE>

The Partnership has also agreed with Paramount that, in conjunction with  the
effectiveness  of  the  Amended  Paramount  Contract,  the  Partnership  will
permanently assign to Paramount or its nominee 6,000 Mcf of the Partnership's
daily  transportation  capacity  rights  under  the  Partnership's  firm  gas
transportation contract for Unit 1 with TransCanada Pipelines Limited.

Indenture  Approval.   The  Partnership's Trust Indenture, dated May 1, 1994,
establishes certain standards which  must  be  satisfied and procedures which
must be completed in order for the Partnership to modify its existing project
agreements in connection with  the  proposed  Unit  1  restructuring.   These
standards  and  procedures  include  without limitation certain findings with
respect to  the  absence  of  a  "Material  Adverse  Change",  which  must be
confirmed in writing by the "Independent Engineer" and the "Gas  Consultant",
in each case as such terms are defined in the Trust Indenture.

Management of the Partnership has evaluated the proposed Unit 1 restructuring
and  determined  that,  based on currently known facts and circumstances, and
certain assumptions which it believes  to  be reasonable, consummation of the
Unit 1 restructuring is in the best interests of the  Partnership  and  could
not reasonably be expected to result in a Material Adverse Change (as defined
in  the  Trust Indenture).  Currently, management is engaged in consultations
with the Independent Engineer, the Gas  Consultant and other advisors for the
purpose of confirming its determinations and carrying out  the  approval  and
certification  procedures  required  by the Trust Indenture for effecting the
necessary project agreement modifications.   In  the  event  that at any time
prior to the Selkirk Closing the Partnership should alter  its  determination
of the absence of Material Adverse Change for any reason, it would not expect
to  consummate  the  Unit 1 restructuring.  In the event that the Partnership
were  to  be  unable to satisfy the standards and complete the procedures for
amending project agreements without bondholder consent which are contained in
the Trust Indenture,  the  Partnership  could  determine to seek bondholders'
consent to the adoption of a supplemental indenture authorizing  the  Unit  1
restructuring.

At  this  time  the  Partnership  is  unable  to  predict  whether it will be
successful in  obtaining  the  required  Indenture  Approval  within the time
limits established under the MRA.   Further,  the  Partnership  expresses  no
opinion  with  respect  to the likelihood that all of the other conditions to
implementation of the MRA will be  met,  nor with respect to the viability of
Niagara Mohawk's proposed alternatives should the implementation of  the  MRA
not  be  completed.   Such  proposed  alternatives  include  Niagara Mohawk's
proposal in the context of the  Power  Choice Statement to take possession of
independent power projects  through  the  power  of  eminent  domain  and  to
thereafter  sell  such  projects or Niagara Mohawk's position that it has not
ruled out  the  ultimate  possibility  of  a  filing  for restructuring under
Chapter 11 of the U.S. Bankruptcy Code as  set  forth  in  the  Power  Choice
Statement.   Nevertheless,  in  the  absence  of  agreement  on  a definitive
restructured power purchase agreement, the Partnership continues to believe

                                     16

<PAGE>

that the existing Niagara Mohawk Power Purchase Agreement  is  a  valid  and
binding contract with Niagara Mohawk.

Previously,  Standard & Poor's placed the Bonds on creditwatch "with negative
implications," based in part on its  analysis  of the public reports filed by
Niagara Mohawk and the Partnership, respectively, and  its  belief  that  the
restructuring  has  the  potential  to  erode cash flow coverage derived from
long-term contracts supporting the Bonds.  To  date Standard & Poor's has not
changed its outlook on the Bonds.  Additionally,  as  of  the  date  of  this
report,  Moody's Investors Service has not changed its rating or its previous
"negative outlook"  on  the  Bonds  based  on  the  developments with Niagara
Mohawk.


Year 2000

Management of the Partnership is conducting  a review of its computer systems
to identify the systems that could be affected by the  new  millennium.   The
year  2000  may  pose problems in software applications because many computer
systems and applications currently use  two-digit  date fields to designate a
year.  As the century date occurs, date sensitive systems may  recognize  the
year  2000  as  1900 or not at all.  This potential inability to recognize or
properly treat the  year  2000  may  cause  systems  to  process financial or
operational information  incorrectly.   Management  has  not  yet  determined
which,  if  any,  systems may be affected and, if affected, the extent of any
potential disruption in operations and  the resulting potential impact on the
Partnership's  ability  to  generate  and  deliver  electricity   or   steam.
Management  has begun to develop and, if required, implement a plan to remedy
any potential  problems  prior  to  the  year  2000.   Management  expects to
finalize this plan, if required, and estimate any  potential  expenses  to  i
mplement  such  plan,  in  1998.   Management  has  not yet assessed expenses
related to year 2000 compliance or the potential impacts of this matter.

                                     17

<PAGE>

									 
                         PART II.		OTHER INFORMATION


ITEM 6.  EXHIBITS AND REPORTS ON FORM 8-K
-----------------------------------------

(A)	Exhibits

	Exhibit No.	          Description					         Page No.
	-----------	          -----------					         --------
		27				  Financial Data Schedule	
						  (For electronic filing purposes only)



(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.




                                     18

<PAGE>

                                 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. 

Date:  May 15, 1998			            /s/   JMC SELKIRK, INC.
                                        --------------------------
 	                                    Name: General Partner
						                 
Date:  May 15, 1998			            /s/  JOHN R. COOPER
                                        --------------------------
 	                                    Name:	John R. Cooper
                                  		Title:	Senior Vice President and
		                                     	and Chief Financial Officer
			
















                                     19


<PAGE>

                  
                                 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:  May 15, 1998			            /s/  JOHN R. COOPER
                                        --------------------------
 	                                    Name:	John R. Cooper
                                  		Title:	Senior Vice President and
		                                     	and Chief Financial Officer
			

						





















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