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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 June 30, 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 August 13, 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 24 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 June 30, 1998 
		and December 31, 1997.........................................	   3

		Condensed Consolidated Statements of Operations for the three 
		and six months ended June 30, 1998 and June 30, 1997..........	   4

		Condensed Consolidated Statements of Cash Flows for the three 
		and six months ended June 30, 1998 and June 30, 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.........................................	   8


		Liquidity and Capital Resources...............................	  10


                         PART II.  OTHER INFORMATION


Item 6.		Exhibits and Reports on Form 8-K........................      22

SIGNATURES..........................................................	  23







                                      2

<PAGE>








                        
<TABLE>
                        SELKIRK COGEN PARTNERS, L.P.
                    CONDENSED CONSOLIDATED BALANCE SHEETS
                               (in thousands)
              
<CAPTION>							
											      (unaudited)
                               			     	  	June 30,    December 31, 
						                              1998		     1997
		                                           ----------	 -----------
<S>												      <C>	       	<C>
ASSETS		
------										
Current assets:									
  Cash............................................ $    1,366     $    1,337 
  Restricted funds................................	   10,551          6,509
  Accounts receivable.............................     17,133         17,764 
  Due from affiliates.............................         59             14 
  Fuel inventory and supplies.....................	    5,092          4,936
  Other current assets............................	      711	         338
  				                   					---------	   ---------
    	Total current assets......................     34,912         30,898 
										
  Plant and equipment, net........................    315,219        321,537 
  Long-term restricted funds......................     24,491         21,494 
  Deferred financing charges, net.................     11,362         11,945 
                                       				---------	   ---------

				Total Asset                        $  385,984     $  385,874
              			                           	---------	   ---------
   			                                      	---------	   ---------
LIABILITIES AND PARTNERS' CAPITAL									
---------------------------------										
Current liabilities:									
  Accounts payable................................ $      126 	  $    1,663 
  Accrued bond interest payable...................	      381 	         382 
  Accrued expenses................................     11,010         14,665 
  Due to affiliates...............................      1,405  	         498 
  Current portion of long-term bonds..............      3,440 	       3,298 
	  					                           	---------	   ---------
	    Total current liabilities................. 	   16,362         20,506 
										
  Other long-term liabilities.....................	   14,785         11,695 
  Long-term bonds, less current portion........... 	  383,932        385,955 
										
  General partners' capital.......................	     (279) 		    (311)
  Limited partners' capital.......................	  (28,816)       (31,971) 
	   				           					    ---------	   ---------
	    Total partners' capital...................    (29,095)       (32,282) 
				                                   	---------	   ---------

				Total Liabilities and
					 Partners' Capital             $  385,984     $  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                  For the 																		
                                Three Months Ended	      Six Months Ended	
                              ---------------------	    --------------------

                               June 30,    June 30,	    June 30,   June 30,
                   		        1998         1997	     1998       1997
               	              ---------   ---------	   ---------   ---------
<S>                              <C>        <C>          <C>          <C>
Operating revenues:								   

 Electric and steam.........  $  37,930      35,533     $ 77,348   $  78,054   
 Gas resale.................      3,187       5,317		   5,178       6,721
               			      ---------   ---------	   ---------   ---------
    Total operating 
      revenues..............	 41,117      40,850 	  82,526	  84,775
Cost of revenue.............     28,770      29,124		  56,878	  60,415
		                 	  ---------   ---------	   ---------   ---------
Gross Profit................     12,347      11,726 	  25,648	  24,360
						 	 	   			
Other operating expenses:										
 Administrative services -
   affiliates...............	    734         729        1,321       1,338 	
 Other general and 
   administrative expenses..	    552      	672        1,096       1,409 	
 Amortization of deferred
   financing charges........	    292         293      	 583         586 	
                    		  ---------   ---------	   ---------   ---------
	Total other operating
	  expenses..............      1,578       1,694        3,000       3,333
		                     ---------   ---------	   ---------   ---------
				 
Operating income............     10,769      10,032 	  22,648      21,027
											
Net interest expense........      7,977       8,046       16,134      16,197 	 
               				  ---------   ---------	   ---------   ---------
Net income..................  $   2,792   $   1,986	   $   6,514   $   4,830
                              ---------   ---------	   ---------   ---------
                      		  ---------   ---------	   ---------   ---------


Allocated to:
  General partners..........  $      28	  $      20    $      65   $     49 
  Limited partners..........	  2,764 	  1,966        6,449      4,781
                              ---------   ---------	   ---------   --------
	Total...................  $   2,792   $   1,986    $   6,514   $  4,830	
                              ---------   ---------    ---------   --------
                              ---------   ---------	   ---------   -------- 
<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                  For the 									
                                Three Months Ended	      Six Months Ended	
                              ---------------------	    --------------------

                               June 30,    June 30,	    June 30,   June 30,
                      		     1998         1997		  1998       1997
               	              ---------   ---------	   ---------   ---------
<S>                              <C>        <C>          <C>          <C>
										                                    		 
Net cash provided by (used in) 
 operating activities.......  $  (3,271)   $   (261)   $  12,290   $  14,021
												
Cash flows provided by 
 (used in) investing 
  activities:											
   Plant and equipment 
    additions...............        (14)        ---          (14)	      34
   Restricted funds.........      5,078		   16,507     (7,039)	     408
                             ---------   ---------	   ---------   ---------
	  			                                    	   
	Net cash provided by (used)
	  investing activities..       5,064      16,507	  (7,053)      	 442
							                         	
Cash flows provided by 
 (used in) financing 
  activities:											
   Cash distributions.......     (3,327)    (14,920)	  (3,327)    (14,920)
   Payments of principal on
    long-term debt..........     (1,881)	 (1,061)      (1,881)	  (1,061)
   Advances from a 
    customer................        ---     	---          ---	     (17)
                               ---------   ---------	---------   ---------
    Net cash used in 
      financing activities..     (5,208)    (15,981)	  (5,208)    (15,998)
												
Net increase (decrease)
 in cash....................      (3,415)        265           29     (1,535)
Cash at beginning 
 of period..................       4,781 	     791	    1,337	   2,591
							  ---------   ---------	    ---------  ---------
Cash at end of period.......  $   1,366   $   1,056     $   1,366   $  1,056
                              ---------   ---------	    ---------  ---------
                      		  ---------   ---------	    ---------  ---------
   
Supplemental disclosures of 
 cash flow information:										

  Cash paid for interest....  $  17,210  $  17,303   $  17,210  $  17,320   				
                              ---------   ---------   ---------   ---------    
		    				  ---------   ---------   ---------   --------- 

<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 and six months ended June 30, 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.


Note 2. New accounting pronouncements 

In April 1998, the American Institute of Certified Public Accountants  issued
Statement  of  Position  98-5 "Reporting on the Costs of Start-Up Activities"
("SOP 98-5").  SOP  98-5  provides  guidance  on  the  financial reporting of
start-up costs  and  organization  costs  ("start-up  costs").   It  requires
start-up costs to be expensed as incurred and previously capitalized start-up
costs  to  be expensed as of the date of adoption.  SOP 98-5 is effective for
fiscal years beginning  after  December  15,  1998.   Management  has not yet
quantified the impact of adopting SOP 98-5.

                                      6
<PAGE>

In June 1998, the Financial Accounting Standards Board  issued  Statement  of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and   Hedging   Activities  ("Statement  133").   Statement  133  establishes
accounting and reporting standards requiring that every derivative instrument
be recorded in the balance sheet as  either an asset or liability measured at
its fair value.  Changes in the derivatives fair value must be recognized  in
the  income  statement  as  a  gain  or loss unless specific hedge accounting
criteria are met.   Statement  133  is  effective  for fiscal years beginning
after June 15, 1999.   Statement  133  must  be  applied  to  (a)  derivative
instruments  and  (b)  certain  derivative  instruments  embedded  in  hybrid
contracts  that  were  issued,  acquired,  or  substantively  modified  after
December  31,  1997 (and, at the company's election, before January 1, 1998).
Management has not yet quantified the impact of adopting Statement 133 on the
Partnership's financial statements and has not  yet determine d the timing of
or method of its adoption of Statement 133.
									   

                                      7
<PAGE>

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

Results of Operations

Three and Six Months Ended June 30, 1998 Compared to the Three and Six Months
Ended June 30, 1997

Net income for the quarter ended June 30, 1998 was approximately $2.8 million
as compared to $2.0 million for the corresponding period in the  prior  year.
Net  income  for  the  six  months ended June 30, 1998 was approximately $6.5
million compared to $4.8 million  for  the  corresponding period in the prior
year.  The increase in net income for the quarter  ended  June  30,  1998  is
primarily  due  to  an increase in delivered energy to Niagara Mohawk and Con
Edison.  The increase in net income for the six months ended June 30, 1998 is
primarily due to an increase in delivered energy to Con Edison and lower fuel
costs.

Total revenues for  the  quarter  and  six  months  ended  June 30, 1998 were
approximately $41.1 million and $82.5 million as compared  to  $40.9  million
and $84.8 million for the corresponding periods in the prior year.

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

								 For the Three Months Ended
                      June 30, 1998                  June 30, 1997 
			  ------------------------------- -------------------------------
	          Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
			  ------- ----- -------- -------- ------- ----- -------- --------
Niagara Mohawk   6.9    58.6  33.23%   39.10%     6.2  27.5   15.74%   18.32%
Con Edison      31.0   504.8  87.22%   94.78%    29.3 418.8   72.33%   81.91%


                                 For the Six Months Ended
                      June 30, 1998                  June 30, 1997	
			  ------------------------------- -------------------------------
	          Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
			  ------- ------ ------- -------- ------- ----- -------- --------
Niagara Mohawk   15.2   161.2 46.19%   51.70%    16.2 188.5   53.43%   58.93%
Con Edison       62.1 1,024.2 88.97%   94.36%    61.7 904.6   78.57%   90.19%



Revenues  from  Niagara Mohawk Power Corporation ("Niagara Mohawk") increased
approximately $0.7 million and  decreased  approximately $1.0 million for the
quarter and six months ended June 30, 1998 as compared to  the  corresponding
periods in the prior year.

                                      8

<PAGE>

The  increase  in  delivered  energy  for  the quarter ended June 30, 1998 as
evidenced by the increase in  the  capacity  factor from 15.74% to 33.23% and
the decrease in delivered energy for the six months ended June  30,  1998  as
evidenced  by  the  decrease in the capacity factor from 53.43% to 46.19% was
the primary contributor  to  the  changes  in  revenues  from Niagara Mohawk.
During the six months ended June 30, 1998, Niagara Mohawk dispatched  Unit  1
on-line  during January, February, May and June and off-line during March and
April.  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  of January and the entire months of May and June were 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 special dispatch arrangements, the Unit would have otherwise
been dispatched off-line.  During the six months ended June 30, 1997, Niagara
Mohawk dispatched Unit 1 on-line during January, February, March and June and
off-line during April and May. Energy delivered during the month of June  was
sold  at  full contract rates.  Energy delivered during January, February and
March were sold  under  special  dispatch  arrangements  which called for the
pricing of delivered energy at variable rates less than full contract  rates.
Revenues  for  energy  pursuant to special dispatch arrangements with Niagara
Mohawk for the quarter and six  months ended June 30, 1998 were approximately
$1.2 million and $1.4 million as compared to $0  and  $4.8  million  for  the
corresponding periods in the prior year.

Revenues  from  Consolidated  Edison Company of New York, Inc. ("Con Edison")
for the quarter and six  months  ended  June 30, 1998 increased approximately
$1.7 million and $0.4 million, respectively  compared  to  the  corresponding
periods  in the prior year.  The increase in delivered energy for the quarter
and six months ended June 30,  1998  as evidenced by the increase in capacity
factor from 72.33% to 87.22% and 78.57%  to  88.97%,  respectively,  was  the
primary contributor to the increase in revenues from Con Edison.

There  were  no  steam  revenues  for the quarter ended June 30, 1998.  Steam
revenues for the six  months  ended  June  30,  1998  of $242.0 thousand were
reduced by a reserve for the same amount to reflect  the  anticipated  annual
true-up  so  that General Electric would be charged a nominal amount which is
the annual equivalent of 160,000lbs/hr.  Steam revenues for the quarter ended
June 30, 1997 were approximately $80.1  thousand.  Steam revenues for the six
months ended June 30, 1997 of $1,053.4 thousand were reduced by a reserve  of
$881.0  thousand  to reflect the anticipated annual true-up.  Delivered steam
for the quarter and six months  ended  June 30, 1998 was 297.6 million pounds
and 683.5 million pounds as  compared  to  322.3  million  pounds  and  828.7
million pounds for the corresponding periods in the prior year.

                                      9

<PAGE>

Gas resale revenues for the quarter ended June 30,  1998  were  approximately
$3.2  million  on sales of 1.3 million MMBtu's as compared to $5.3 million on
sales of 2.3 million MMBtu's for  the corresponding period in the prior year.
Gas resale revenues for the six months ended June 30, 1998 were approximately
$5.2 million on 2.2 million MMBtu's as compared to approximately $6.7 million
on sales of 2.8 million MMBtu's for the corresponding  period  in  the  prior
year.   The  $2.1  million decrease in gas resale revenues during the quarter
ended June 30, 1998 was primarily  due  to  higher dispatch of Units 1 and 2,
which resulted in lower volumes of natural gas becoming available for resale.
The $1.5 million decrease in gas resale revenues during the six months  ended
June 30, 1998 was primarily due to lower natural gas resale prices and higher
dispatch  of  Unit 2, which resulted in lower volumes of natural gas becoming
available for resale at  lower  prices.   The  decrease in natural gas resale
prices during the six months ended June 30, 1998 generally resulted from more
moderate temperatures in the Northeast  region  as  compared  to  the  colder
temperatures,  which  resulted  in  higher 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  and  six  months  ended June 30, 1998 were
approximately $28.8 million and $56.9 million on  purchases  of  7.1  million
MMBtu's  and  14.1 million MMBtu's as compared to approximately $29.1 million
and $ 60.4 million  on  purchases  of  7.1  million  MMBtu's and 14.0 million
MMBtu's for the  corresponding  periods  in  the  prior  year.   The  largest
component  of the decrease for the quarter and six months ended June 30, 1998
was fuel costs,  which  decreased  $0.5  million  and  $3.7  million from the
corresponding period in 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.  During the quarter and six months ended June  30,  1998,  firm  fuel
purchases  from  suppliers were comparable to the corresponding period in the
prior year.

Total other operating expenses for the  quarter and six months ended June 30,
1998 were  approximately  $1.6  million  and  $3.0  million  as  compared  to
approximately  $1.7 million and $3.3 million for the corresponding periods in
the prior year.  The decrease in other operating expenses is primarily due to
a decrease in consulting and legal fees.

Net interest expense for the quarter  and  six  months ended June 30, 1998 of
approximately  $8.0  million  and  $16.1  million  are  comparable   to   the
corresponding periods in the prior year.


Liquidity and Capital Resources

Net  cash  flows  used in operating activities for the quarter ended June 30,
1998 was approximately  $3.3  million  as  compared  to  $0.3 million for the
corresponding period in the prior year.  Net cash flows provided by operating
activities for the six months ended June 30,  1998  was  approximately  $12.3
million  as  compared  to  $14.0  million for the corresponding period in the
prior year.  The increase in net  cash flows used in operating activities and
decrease in net cash flows provided by operating activities for  the  quarter
and  six  months  ended  June  30,  1998, respectively, is primarily due to a
decrease in net operating cashflows resulting from normally recurring changes
in cash receipts and  disbursements  within the Partnership's operating asset
and liability accounts and the $2.2 million payment made in conjunction  with
the  MRA  (see  MRA  discussion  below)  offset by the increase in net income
during the quarter and six months ended June 30, 1998.

                                      10

<PAGE>

Net cash flows provided by (used in) investing activities for the quarter and
six months ended June  30,  1998  were  approximately  $5.1 million and ($7.1
million) as compared to approximately $16.5 million and $0.4 million for  the
corresponding  periods  in  the prior year.  Net cash flows provided by (used
in) investing activities represent  monies  withdrawn  from or deposited into
funds created pursuant  to  the  Partnership's  Depositary  and  Disbursement
Agreement,  administered  by  Bankers Trust Company, as depositary agent (the
"Funds").  Net cash flows  provided  by  investing activities for the quarter
ended June 30, 1998 primarily represent monies withdrawn  from  the  Interest
Fund for payment to the Bondholders offset by monies deposited into the Major
Maintenance   Reserve   Fund,  Debt  Service  Reserve  Fund  and  Partnership
Distribution Fund.  Net cash flows  used  in investing activities for the six
months ended June 30, 1998 primarily  represent  monies  deposited  into  the
Major  Maintenance  Reserve  Fund,  Debt Service Reserve Fund and Partnership
Distribution Fund.
 
Net cash flows  used  in  financing  activities  decreased from approximately
$16.0 million for  the  quarter  and  six  months  ended  June  30,  1997  to
approximately  $5.2  million  for  the  quarter and six months ended June 30,
1998.  The decrease in net cash  flows  for  the quarter and six months ended
June 30, 1998 is primarily due to a decrease in distributions to Partners.

The Partnership entered into a Master Restructuring Agreement (as amended  on
March 31, 1998, April 21, 1998, April 30, 1998, May 7, 1998 and June 2, 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").  The  closing  of  the  transactions  provided
under  the  MRA for the Settling IPP's other than the Partnership occurred on
June 30, 1998 (the "Other Settling  IPP  Closing").  Pursuant to the terms of
the MRA, the closing of the MRA  transactions  between  the  Partnership  and
Niagara Mohawk may be deferred until August 31, 1998 and, further, is subject
to   the   satisfaction   of  certain  standards  and  procedures  under  the
Partnership's Trust Indenture, dated as of  May 1, 1994 (the "Indenture"), as
described below.  If the Partnership and Niagara Mohawk proceed  to  complete
the  transactions  provided  under  the  MRA,  the  existing  Power  Purchase
Agreement  between  the Partnership and Niagara Mohawk (the " Existing Unit 1
Agreement") will be amended and  restated  to  modify  the basis on which the
Partnership makes sales of the electrical capacity and output of Unit 1  (the
"Amended  and  Restated  Unit  1  Agreement").   For a description of certain
applicable provisions  of  the  MRA  and  related  transactions  see  "Unit 1
Restructuring" below.  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 net 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 Indenture and would, therefore, not be
obligated to proceed further under the MRA.  For the quarter and  six  months
ended  June  30,  1998, capacity and energy sales to Niagara Mohawk accounted
for approximately 16.8% and 18.4%, respectively of total project revenues.

                                      11

<PAGE>

In 1994 and 1995 Con Edison 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  ("non-plant  gas"),  or
alternatively  to  be  compensated  for  100%  of  the  margins  derived from
non-plant gas sales.  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 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 exercise such  rights.   The
Partnership vigorously disputes the position adopted by Con Edison, and since
the  commencement  of  Unit  2's  operation in 1994 has made and continues to
make, from time  to  time,  non-plant  gas  sales  from  Unit 2's gas supply.
Although representatives of Con Edison have  expressly  reserved  all  rights
which  Con  Edison  may  have  to  pursue  its asserted claim with respect to
non-plant  gas  sales,  the  Partnership   has  received  no  further  formal
communication from Con Edison on this subject since 1995.  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.
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.

On July 21, 1998 the New York Public Service Commission ("NYPSC") approved  a
plan submitted by Con Edison for the divestiture of certain of its generating
assets  (the  "Con  Edison  Divestiture  Plan").   Although  the  Con  Edison
Divestiture  Plan does not include any proposal by Con Edison for the sale or
other disposition of its  contractual  obligations  for purchasing power from
non-utility generators, like the  Partnership,  the  NYPSC  has  ordered  Con
Edison  to  submit  a  report  regarding  the  feasibility  of  divesting its
non-utility  generator  entitlements.   At  this  time,  the  Partnership has
insufficient information  to  determine  whether,  in  the  course  of  these
proceedings  at  the  NYPSC,  Con  Edison  may  seek to assign its rights and
obligations  under  the  Con   Edison   Power  Purchase  Agreement  with  the
Partnership to a third party or to take some other action for the purpose  of
divesting  itself  of the power purchase obligations under such contract; nor
can the Partnership evaluate the  impact  which  any such assignment or other
action, if proposed, may ultimately have on the  Con  Edison  Power  Purchase
Agreement.

                                      12

<PAGE>

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
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
generators  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
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.  On June 30,
1998 the MRA was consummated as  to twenty-six power purchase agreements (not
including the Partnership's Existing Unit 1 Agreement).

In conjunction with the Other Settling IPP Closing, 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 and the modification  of  existing
contractual arrangements with third parties either had been satisfied or were
being  waived by the Partnership.  The single exception which continues to be
a condition to  the  Partnership's  obligation  to undertake the transactions
contemplated by the MRA is a determination by the Partnership  that  it  will
undertake  the  Unit  1  restructuring  without  a vote of its bondholders as
permitted by the Indenture, or alternatively,  receipt of the approval of the
Partnership's  bondholders  to  the  Unit  1  restructuring  (the  "Indenture
Approval").  Although the MRA established June 30, 1998 as the  closing  date
for  the transactions with the other Settling IPP's, 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
and the Existing Unit 1 Agreement will remain in effect.

                                      13

<PAGE>

At  the  Other  Settling  IPP  Closing,  the Partnership made $2.2 million in
payments related to the agreed allocation among the Settling IPP's of certain
costs and  benefits.   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, a cash  payment  currently  estimated  to  total  $10.3  million
(representing net receipts to the Partnership of approximately $8.1 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 its Report on Form 10-Q for the
fiscal quarter ended March 31,  1998  filed  with the Securities and Exchange
Commission on May 15, 1998, the Partnership described the form of the Amended
and Restated Unit 1 Agreement (including the forms  of  an  indexed  electric
rate ISDA swap contract and a power put agreement) which had been agreed with
Niagara  Mohawk in contemplation of the Other Settling IPP Closing (the "June
30 Version of the Amended and  Restated  Unit 1 Agreement").  Since the Other
Settling IPP Closing the Partnership and Niagara Mohawk have been engaged  in
negotiation  of  substantive  modifications  to  the  June  30 Version of the
Amended and Restated Unit  1  Agreement.   The Partnership and Niagara Mohawk
are in the process of  executing  a  modified  version  of  the  Amended  and
Restated  Unit  1 Agreement (the "Revised Version of the Amended and Restated
Unit 1 Agreement")  which  is  intended  to  be  substituted  for the June 30
Version of the Amended and Restated Unit 1 Agreement (including  the  indexed
electric  rate  ISDA  swap contract and power put agreement) in its entirety.
The effectiveness of the Revised Version  of  the Amended and Restated Unit 1
Agreement is subject to the occurrence of the Selkirk Closing.  The following
discussion under this caption "Amended and Restated  Unit  1  Agreement",  is
intended  to  present only the broad outlines of the principal terms included
in the Revised Version of the Amended and Restated Unit 1 Agreement.

                                     14

<PAGE>

If and when the  Amended  and  Restated  Unit  1  Agreement goes into effect,
except for Niagara Mohawk's transitional call rights described below, 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 ten-year term of  the
Amended  and  Restated  Unit  1  Agreement, however, will be mitigated by the
payment obligations of Niagara Mohawk  under  the Amended and Restated Unit 1
Agreement.   Over  the  comparable  period,  these  payment  obligations  are
projected by the Partnership  to  exceed  substantially  the  expected  fixed
payment  obligations  due  from  Niagara  Mohawk  under  the  Existing Unit 1
Agreement.  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.

Sale  Option.   From  the  effective  date of the Amended and Restated Unit 1
Agreement until the first day  of  the  calendar month following the month in
which an Independent System Operator/Power Exchange ("ISO/PE") in New York is
established and fully functioning in accordance with standards set  forth  in
the contract, the Partnership will have the option to sell and deliver energy
and  associated capacity to Niagara Mohawk up to a specified Monthly Contract
Quantity, plus up to  5%  of  the  Monthly Contract Quantity ("Sale Option").
The annual contract volumes and notional contract quantities upon  which  the
Monthly Contract Quantities are based are set forth below.

			      	--------------------------------
	                      	     Annual
				               Contract   	Notional
                    Contract     Volume    Quantity
                    Year 		  MWh 	       MW
	             	--------------------------------
               		1     	   325,400 	     37.146
 		      		2          331,000       37.785
                    3          375,900       42.911
                    4          417,500       47.660
                    5          419,500       47.888
                    6          442,000       50.457
                    7          451,700       51.564
                    8          461,300       52.660
                    9          473,400       54.041
                   10          485,200       55.388
             	   ---------------------------------

Upon  prior  notice  to  Niagara  Mohawk, the Partnership will have the right
under the Amended and  Restated  Unit  1  Agreement  to sell and deliver Sale
Option power to Niagara Mohawk for periods ranging from one hour to  over  12
months.   The  energy  and  capacity  the Partnership sells to Niagara Mohawk
pursuant to the  Sale  Option  can  be  produced  by  Unit  1,  Unit  2 or an
alternative source.  The Partnership will  not  object  to  Niagara  Mohawk's
inclusion  of  capacity associated with the notional quantity set forth above
as capacity available to Niagara Mohawk for regulatory purposes.
                                     
                                      15

<PAGE>

Niagara Mohawk will be required to take  and pay for such energy and capacity
as the Partnership delivers to it under the Sale Option at the Market  Energy
Price,  and,  if  applicable,  the  Market Capacity Price.  During the period
prior to the establishment of the ISO/PE and its implementation of locational
based market pricing (as described  below),  the  Market Energy Price will be
Niagara Mohawk's short-term avoided energy and capacity costs at the location
of its energy delivery point, as stated in Niagara Mohawk's  tariff  for  the
purchase  of  power  from  "qualifying  facilities"  under the Public Utility
Regulatory Policies Act of 1978,  as amended ("Initial Market Energy Price").
Beginning on the first day of the month after the ISO/PE is  established  and
implementing locational based market pricing, the Market Energy Price will be
the day ahead locational based market price, published by the ISO/PE, paid to
sellers  for  energy  at the Partnership's delivery point, unless the parties
mutually agree to continue to use the Initial Market Energy Price.

Unless the parties agree to continue  to use the Initial Market Energy Price,
the Market Capacity Price will be:  (i) equal to zero during the period prior
to the establishment of the ISO/PE and any time thereafter when  no  separate
capacity  market  exists;  and  (ii)  beginning on the first day of the month
after the ISO/PE  is  established  and  only  if  a  separate capacity market
exists, equal to the market  price  paid  to  sellers  for  capacity  at  the
Partnership's  energy delivery point as established by the ISO/PE in capacity
auctions.

For any time-period during which the  Partnership decides not to exercise its
Sale Option to Niagara Mohawk, the  Partnership  may  sell  such  energy  and
associated  capacity  to third parties, provided that it first offers Niagara
Mohawk the opportunity to  purchase  that  energy  and capacity at the Market
Energy Price, and, if applicable,  the  Market  Capacity  Price  and  Niagara
Mohawk declines.  The Partnership is free under the Amended and Restated Unit
1  Agreement  to sell energy and associated capacity in excess of the Monthly
Contract Quantity to third parties  without  giving Niagara Mohawk a right of
first refusal.

Niagara Mohawk's Call Option.  Solely during  the period in which the Initial
Market Energy Price is in effect, but no later than twenty-four  (24)  months
after  July  1, 1998, under the Amended and Restated Unit 1 Agreement Niagara
Mohawk will have the right ("Call Option"), subject to certain conditions, to
schedule deliveries of  energy  from  Unit  1  up  to  the applicable Monthly
Contract Quantity ("Call Option Quantity") provided these quantities are  not
already  committed  to  Niagara  Mohawk or third-parties pursuant to the Sale
Option provisions of the contract.   The  Partnership will be relieved of its
obligation to sell and deliver the Call Option Quantity to Niagara Mohawk  in
the  event  that  Unit  1  is  unavailable for any reason.  If Niagara Mohawk
exercises its Call Option, the Partnership has the right to sell and deliver,
and Niagara Mohawk  has  the  obligation  to  take  and  pay  for, all energy
produced by Unit 1 which exceeds the Call Option Quantity ("Excess  Energy").
The price Niagara Mohawk will pay for the Call Option Quantity and the Excess
Energy  will be the higher of (a) the Initial Market Energy Rate, and (b) the
Partnership's variable gas  opportunity  costs  and operation and maintenance
costs ("Variable Energy Price").

                                      16

<PAGE>

Right of First Refusal.  Niagara Mohawk will have a right of first refusal to
purchase  energy  and/or  capacity  up  to  the  applicable  Monthly Contract
Quantity during the  ten-year  term  of  the  Amended  and  Restated  Unit  1
Agreement.   Accordingly,  before  the  Partnership  may sell such energy and
associated capacity to third parties, it  must first offer Niagara Mohawk the
opportunity to purchase that energy and capacity at the Market Energy  Price,
and,  if  applicable, the Market Capacity Price.  If Niagara Mohawk declines,
the Partnership may sell such power  to third parties.  Energy and associated
capacity in excess of the Monthly Contract Quantity is not subject to Niagara
Mohawk's right of first refusal.

Monthly Payment Obligations.  The monthly payment  equals  the  sum  of  four
components:    (1)   a  Capacity  Payment;  (2)  an  Energy  Payment;  (3)  a
Transportation Payment; and (4)  an  Operation  and Maintenance Payment.  The
Capacity Payment, Transportation Payment, Operation and  Maintenance  Payment
and  a  fixed  portion  of  the Energy Payment are payable whether or not the
Partnership sells energy or capacity to Niagara Mohawk.  The variable portion
of the Energy  Payment  varies  with  the  quantities  of energy and capacity
actually sold to Niagara Mohawk pursuant to the Sale Option, Call  Option  or
exercise  by  Niagara  Mohawk  of its right of first refusal.

Niagara Mohawk will be obligated to pay the Partnership the  monthly  payment
to the extent such number is positive, and, the Partnership will be obligated
to  pay  Niagara  Mohawk  the  monthly  payment  to the extent such number is
negative.  Since the Capacity  Payment  and  the  fixed portion of the Energy
Payment are offset by actual market  prices,  during  periods  in  which  the
Market  Energy  Price  or  Market  Capacity  Price  is high, the sum of these
payments could result in a  negative  number.   In such event the Partnership
would be obligated to make payments to Niagara Mohawk.  Under the Amended and
Restated Unit 1 Agreement, the Partnership at all times retains the right  to
sell  Unit  1  energy  and associated capacity at the prevailing market price
(assuming the plant  is  available  for  generation).   The Partnership would
expect net revenues from such sales to mitigate the impact of any payments it
may be required to make to Niagara Mohawk  during  periods  in  which  actual
market prices are high.

                                      17

<PAGE>

The monthly payment under the Amended and Restated Unit 1 Agreement is to  be
calculated as follows:

1.  The "Capacity Payment" will equal the difference between (A) the Contract
Capacity  Payment and (B) the Market Capacity Payment.  The Contract Capacity
Payment will equal the product of  (i) a specified annual capacity rate, (ii)
the Monthly Contract Quantity  and  (iii)  the  DMNC  Adjustment.   The  DMNC
Adjustment  is  a  quotient,  the  numerator  of  which  is  the actual rated
Dependable Maximum Net Capability of Unit  1  and the denominator of which is
79.9 MW (except when the Partnership is obligated to make the monthly payment
to Niagara Mohawk in which case the DMNC Adjustment is one (1)).  The  Market
Capacity  Payment will equal the product of the Market Capacity Price and the
weighted averaged capacity associated with  the Notional Quantity of capacity
for the period.  

2.   The  "Energy  Payment"  will  equal  the  sum of (A) the Contract Energy
Payment, (B) the Delivered Energy Payment, (C) the Delivered Capacity Payment
and (D) the Call Energy Payment.   The Contract Energy Payment will equal the
product of (i) the difference between  the  Contract  Energy  Price  and  the
Market  Energy  Price,  (ii) the Monthly Contract Quantity and (iii) the DMNC
Adjustment.  The Contract Energy Price for  the first two contract years will
be fixed; thereafter, the Contract Energy Price will consist of the heat rate
of 10,950 MMBtu/MWh multiplied by 105% of the current month's spot gas  price
at  the  Empress  border  (the  "Empress  spot price").  The Delivered Energy
Payment will equal  the  amount  of  energy  actually  sold to Niagara Mohawk
either under the Sale Option or at Niagara Mohawk's election under its  right
of  first  refusal,  multiplied  by  the  Market Energy Price.  The Delivered
Capacity Payment will equal the  amount  of capacity actually sold to Niagara
Mohawk either under the Sale Option or at Niagara Mohawk's election under its
right of first refusal, multiplied by the Market Capacity  Price.   The  Call
Energy  Payment will equal the Call Option Quantity and Excess Energy sold to
Niagara Mohawk during a  Call  Option  period,  multiplied by the Call Energy
Price.  The Call Energy Price will be the higher of the Initial Market Energy
Rate and the Partnership's Variable Energy Costs on the day  of  delivery  of
the Call Quantity.

3.  The "Transportation  Payment"  will  be  the  product  of (A) a specified
annual transportation rate, which is adjusted to reflect changes  since  July
1,  1998 in the consumer price index for urban consumers in New York-Northern
New Jersey-Long  Island  (the  "CPI  Adjustment"),  (B)  the Monthly Contract
Quantity and (C) the DMNC Adjustment. 

4.  The "Operation and Maintenance Payment" will be  the  product  of  (A)  a
specified  annual O & M rate, which is subject to the CPI Adjustment, (B) the
Monthly Contract Quantity and (C) the DMNC Adjustment.

                                      18

<PAGE>

Term.  The term of the Amended  and  Restated  Unit 1 Agreement is ten years.
It will be effective as of July 1, 1998 (assuming the Selkirk Closing occurs)
and terminate on June 20, 2008.

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  fixed  portion  of  the  Energy Payment under 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.

The  Partnership has also agreed with Paramount that, in conjunction with the
effectiveness of the Amended  Paramount  Contract, the Partnership will enter
into  arrangements  to  release  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
("TransCanada"), in conjunction with Paramount's acquiring 6,000 Mcf of daily
transportation capacity rights on TransCanada's pipeline system.

Indenture   Approval.   The  Indenture  prohibits  any  modification  to  the
Partnership's material project  agreements  unless  the proposed modification
satisfies the requirements of at least one of several  specified  exceptions.
One of the exceptions under the Indenture (hereinafter referred to as the "No
Material  Adverse  Change  Exception")  permits the Partnership to terminate,
amend or modify any of  its  material  project agreements if the termination,
amendment or modification could not reasonably be expected  to  result  in  a

                                      19

<PAGE>

"Material Adverse Change" (as defined in  the  Indenture) and, in the case of
any such termination, amendment or modification that would materially  change
the pricing or volume provisions or reduce the duration of certain agreements
(including  the  Existing  Unit 1 Agreement, the existing Unit 1 Gas Purchase
Contract with Paramount and the  existing  Unit 1 Gas Transportation Contract
with TransCanada), such determination is concurred with by  the  "Independent
Engineer"  (or  the  "Gas  Consultant"  with respect to the Partnership's gas
contracts).  The "Independent  Engineer"  under  the  Indenture is R.W. Beck,
Inc.; the "Gas Consultant" under the Indenture is  C.C.  Pace  Resources.   A
second  exception  under  the  Indenture  (hereinafter  referred  to  as  the
"Projected   Debt  Service  Coverage  Exception")  permits  the  termination,
amendment or modification of any  such agreement if the Partnership certifies
to the Trustee, and such certification is concurred with by  the  Independent
Engineer,  that after giving effect to the proposed termination, amendment or
modification, the minimum annual "Projected  Debt Service Coverage Ratio" (as
defined in the Indenture) will be equal to or exceed 1.5:1  and  the  average
annual  Projected  Debt  Service  Coverage  Ratio  will be equal to or exceed
1.75:1.

The  Partnership  has  determined  that,  based  on currently known facts and
circumstances, and certain assumptions  which  it  believes to be reasonable,
the Partnership's entering into the Amended and Restated Unit 1 Agreement and
the  Amended  Paramount  Agreement  and  the  consummation   of   the   other
transactions  contemplated by such modified project agreements and by the MRA
(collectively, "Unit 1  restructuring")  will  satisfy  both  the No Material
Adverse Change Exception and the Projected Debt Service  Coverage  Exception.
Currently, management of the Partnership is undertaking (in consultation with
the  Independent Engineer, the Gas Consultant, Standard & Poor's Corporation,
Moody's Investors Services, Inc.  and  other  advisors) to confirm certain of
the facts, circumstances and assumptions upon  which  this  determination  is
based.   If  the  Partnership  elects  to  proceed  to  consummate the Unit 1
restructuring in accordance with the  No Material Adverse Change Exception or
the Projected Debt Service Coverage Exception (or  both)  ,  the  Partnership
will  deliver  to  the Trustee the certifications of the Independent Engineer
and the Gas  Consultant  necessary  to  comply  with  the No Material Adverse
Change Exception, and if applicable  the  certification  of  the  Independent
Engineer  necessary  to  comply  with  the  Projected  Debt  Service Coverage
Exception.

For purposes of preparing the  projections  from which projected debt service
coverage ratios are derived, certain assumptions must be made, of  necessity,
with  respect  to  general business and economic conditions, the revenues the
Partnership will receive for  electric  energy  and  steam  and the resale of
natural gas, the cost to the Partnership of obtaining  natural  gas  supplies
and  several  other  material  contingencies  and  other matters that are not
within the control of  the  Partnership  and  the  outcome of which cannot be
predicted.  These assumptions and the other assumptions used in such analysis
are inherently subject to significant uncertainties and actual  results  will
differ,  perhaps  materially,  from those projected.  While these assumptions
are based  on  currently  known  information  and  are  dependent upon future
events, the Partnership and the Independent  Engineer  will  certify  to  the
Trustee,  as  required  under  the Indenture, that the assumptions upon which
such projections are based are  reasonable and materially consistent with the
Partnership's project agreements and historical  operating  results,  in  the
event that the Partnership proceeds to consummate the Unit 1 restructuring.

                                      20

<PAGE>

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.  In the event that at any time prior to the
Selkirk Closing the Partnership  should  alter  its  determination  that  the
proposed  Unit 1 restructuring satisfies the requirements for the No Material
Adverse Change Exception or  the  Projected  Debt Service Coverage Exception,
the Partnership would not expect to consummate the transactions with  Niagara
Mohawk  contemplated  under the MRA.  The failure of the Amended and Restated
Unit 1  Agreement  to  become  effective  will  not  affect  the  validity or
enforceability of the  Existing  Unit  1  Agreement,  which  the  Partnership
believes  continues  to  be  the  binding  contractual  obligation of 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  developed  and  is
implementing a plan to remedy any potential problems with management  systems
prior to the year 2000.  Management has also instructed its operator, General
Electric, to develop and implement such a plan with respect to the Facility's
operating  systems,  however,  General  Electric has not yet agreed to do so.
Management has tentatively assessed expenses  related to year 2000 compliance
to be approximately $300,000,  which  is  subject  to  change  as  conditions
warrant.
                                      21

<PAGE>



PART II.		OTHER INFORMATION

ITEM 5. OTHER INFORMATION
        -----------------

Pursuant  to  a  Purchase  Agreement  dated  as  of  March  6,  1998, Bechtel
Generating Company has agreed to sell  its indirect ownership interest in the
Partnership to Cogentrix Energy, Inc. The Partnership expects the transaction
to close during the third quarter of 1998.


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.
	
                                     22

<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: August 14, 1998	    	          /s/    JMC SELKIRK, INC.
                                        --------------------------
 	                                    		General Partner


Date: August 14, 1998	        	      /s/    JOHN R. COOPER
                                        --------------------------
 	                                     Name:  John R. Cooper
                                         Title:	Senior Vice President and
		                                         and Chief Financial Officer

			

						















                                      23

<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: August 14, 1998	 	              /s/    JOHN R. COOPER
                                        --------------------------
 	                                     Name:  John R. Cooper
                                         Title:	Senior Vice President and
		                                         and Chief Financial Officer
			

						




















                                      24