CONFORMED COPY
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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
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<ARTICLE> 5
<CIK> 000929540
<NAME> SELKIRK COGEN PARTNERS, L.P.
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> Dec-31-1998
<PERIOD-START> Jan-01-1998
<PERIOD-END> Jun-30-1998
<CASH> 1366
<SECURITIES> 0
<RECEIVABLES> 17192
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<DEPRECIATION> 56080
<TOTAL-ASSETS> 385984
<CURRENT-LIABILITIES> 16362
<BONDS> 383932
0
0
<COMMON> 0
<OTHER-SE> (29095)
<TOTAL-LIABILITY-AND-EQUITY> 385984
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