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 March 31, 1998
Commission File Number 33-83618
SELKIRK COGEN PARTNERS, L.P.
(Exact name of Registrant (Guarantor) as specified in its charter)
Delaware 51-0324332
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
SELKIRK COGEN FUNDING CORPORATION
(Exact name of Registrant as specified in its charter)
Delaware 51-0354675
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
One Bowdoin Square, Boston, Massachusetts 02114
(Address of principal executive offices, including zip code)
(617) 227-8080
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
8.65% First Mortgage Bonds Due 2007, Series A
8.98% First Mortgage Bonds Due 2012, Series A
(Title of class)
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No
--- ---
As of May 15, 1998, there were 10 shares of common stock of Selkirk Cogen
Funding Corporation, $1 par value outstanding.
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This document consists of 20 pages of which this page is page 1.
<PAGE>
TABLE OF CONTENTS
Page
----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)
Condensed Consolidated Balance Sheets as of March 31, 1998
and December 31, 1997......................................... 3
Condensed Consolidated Statements of Operations for the three
months ended March 31, 1998 and March 31, 1997................ 4
Condensed Consolidated Statements of Cash Flows for the three
months ended March 31, 1998 and March 31, 1997................ 5
Notes to Condensed Consolidated Financial Statements.......... 6
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Results of Operations......................................... 7
Liquidity and Capital Resources............................... 9
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K.......................... 18
SIGNATURES............................................................ 19
2
<PAGE>
<TABLE>
SELKIRK COGEN PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
<CAPTION>
(unaudited)
March 31, December 31,
1998 1997
---------- ------------
<S> <C> <C>
ASSETS
Current assets:
Cash............................................ $ 4,781 $ 1,337
Restricted funds................................ 17,431 6,509
Accounts receivable............................. 15,608 17,764
Due from affiliates............................. 14 14
Fuel inventory and supplies..................... 5,066 4,936
Other current assets............................ 235 338
--------- ---------
Total current assets...................... 43,135 30,898
Plant and equipment, net........................ 318,371 321,537
Long-term restricted funds...................... 22,689 21,494
Deferred financing charges, net................. 11,654 11,945
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Total Assets $ 395,849 $ 385,874
--------- ---------
--------- ---------
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable................................ $ --- $ 1,663
Accrued bond interest payable................... 8,987 382
Accrued expenses................................ 11,752 14,665
Due to affiliates............................... 476 498
Current portion of long-term bonds.............. 3,298 3,298
--------- ---------
Total current liabilities................. 24,513 20,506
Other long-term liabilities..................... 13,942 11,695
Long-term bonds, less current portion........... 385,955 385,955
General partners' capital....................... (274) (311)
Limited partners' capital....................... (28,287) (31,971)
--------- ---------
Total partners' capital................... (28,561) (32,282)
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Total Liabilities and
Partners' Capital $ 395,849 $ 385,874
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--------- ---------
<FN>
See Notes to Condensed Consolidated Financial Statements.
</TABLE>
3
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<TABLE>
SELKIRK COGEN PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
(unaudited)
<CAPTION>
For the Three Months Ended
--------------------------
March 31, March 31,
1998 1997
---------- ----------
<S> <C> <C>
Operating revenues:
Electric and steam............................ $ 39,418 $ 42,521
Gas resale.................................... 1,991 1,404
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Total operating revenues.................. 41,409 43,925
Cost of revenue................................... 28,108 31,291
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Gross Profit...................................... 13,301 12,634
Other operating expenses:
Administrative services - affiliates.......... 587 609
Other general and administrative expenses..... 544 737
Amortization of deferred financing charges.... 291 293
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Total other operating expenses............ 1,422 1,639
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Operating income.................................. 11,879 10,995
Net interest expense.............................. 8,157 8,151
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Net income........................................ $ 3,722 $ 2,844
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Allocated to:
General partners.............................. $ 37 $ 29
Limited partners.............................. 3,685 2,815
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Total..................................... $ 3,722 $ 2,844
--------- ---------
--------- ---------
<FN>
See Notes to Condensed Consolidated Financial Statements.
</TABLE>
4
<PAGE>
<TABLE>
SELKIRK COGEN PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
<CAPTION>
For the Three Months Ended
--------------------------
March 31, March 31,
1998 1997
---------- ----------
<S> <C> <C>
Net cash provided by operating activities......... $ 15,561 $ 14,282
Cash flows provided by (used in)
investing activities:
Plant and equipment additions................. --- 34
Restricted funds.............................. (12,117) (16,099)
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Net cash used in investing activities..... (12,117) (16,065)
Cash flows used in financing activities:
Advances from a customer...................... --- (17)
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Net cash used in financing activities..... --- (17)
Net decrease in cash.............................. 3,444 (1,800)
Cash at beginning of period....................... 1,337 2,591
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Cash at end of period............................. $ 4,781 $ 791
--------- ---------
--------- ---------
Supplemental disclosures of cash flow information:
Cash paid for interest........................ $ --- $ 17
--------- ---------
--------- ---------
<FN>
See Notes to Condensed Consolidated Financial Statements.
</TABLE>
5
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SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1. Basis of Presentation
The accompanying unaudited condensed consolidated financial statements
consolidate Selkirk Cogen Partners, L.P. and its wholly-owned subsidiary,
Selkirk Cogen Funding Corporation, (collectively the "Partnership"). All
significant intercompany accounts and transactions have been eliminated.
The condensed consolidated financial statements for the interim periods
presented are unaudited and have been prepared pursuant to the rules and
regulations of the Securities and Exchange Commission. The information
furnished in the condensed consolidated financial statements reflects all
normal recurring adjustments which, in the opinion of management, are
necessary for a fair presentation of such financial statements. Certain
information and footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting
principles have been condensed or omitted pursuant to rules and regulations
applicable to interim financial statements. Certain reclassifications have
been made to the Condensed Consolidated Statements of Operations for the
three months ended March 31, 1997 to conform with the current period's basis
of presentation.
These condensed consolidated financial statements should be read in
conjunction with the audited consolidated financial statements included in
the Partnership's December 31, 1997 Annual Report on Form 10-K.
6
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
------------------------------------------------------------------------
RESULTS OF OPERATIONS
---------------------
Results of Operations
Three Months Ended March 31, 1998 Compared to the Three Months Ended
March 31, 1997
Net income for the quarter ended March 31, 1998 was approximately $3.7
million as compared to $2.8 million for the corresponding period in the prior
year. The $0.9 million increase in net income is primarily due to a $0.6
million increase in gas resale revenues and a $0.2 million decrease in other
general and administrative expenses.
Total revenues for the quarter ended March 31, 1998 were approximately $41.4
million as compared to $43.9 million for the corresponding period in the
prior year.
Electric Revenues (dollars and kWh's in millions):
- --------------------------------------------------
For the Three Months Ended
March 31, 1998 March 31, 1997
------------------------------- -------------------------------
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ----- -------- --------
Niagara Mohawk 8.3 102.6 59.43% 64.44% 10.0 161.1 90.31% 100.00%
Con Edison 31.1 519.4 90.75% 93.94% 32.4 485.9 84.88% 98.56%
Revenues from Niagara Mohawk Power Corporation ("Niagara Mohawk") for the
quarter ended March 31, 1998 decreased approximately $1.7 million as compared
to the corresponding period in the prior year. A decrease in delivered
energy as evidenced by the decrease in the capacity factor from 90.31% to
59.43% was the primary contributor to the decrease in revenues. During the
quarter ended March 31, 1998, Niagara Mohawk dispatched Unit 1 on-line during
January and February and off-line during March. Energy delivered during the
majority of January and the entire month of February was sold at full
contract rates. Energy delivered during the first four days in January was
sold under special dispatch arrangements which called for the pricing of
delivered energy at variable rates less than full contract rates. Had the
Partnership not entered into the special dispatch arrangements, the Unit
would have otherwise been dispatched off-line. During the quarter ended
March 31, 1997, Niagara Mohawk dispatched Unit 1 on-line and all of the
energy delivered was sold under special dispatch arrangements which called
for the pricing of delivered energy at variable rates less than full contract
rates. Revenues for energy delivered pursuant to special dispatch
arrangements with Niagara Mohawk for the quarter ended March 31, 1998 were
approximately $0.2 million as compared to $4.8 million for the corresponding
period in the prior year.
7
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Revenues from Consolidated Edison Company of New York, Inc. ("Con Edison")
for the quarter ended March 31, 1998 decreased approximately $1.3 million as
compared to the corresponding period in the prior year. A decrease in
contract energy rates resulting from lower index fuel prices was only partly
offset by an increase in delivered energy (as evidenced by the increase in
the capacity factor from 84.88% to 90.75%) and was the principal factor
contributing to the decrease in revenues.
Pursuant to the Steam Sales Agreement, General Electric is charged a nominal
amount which is the annual equivalent of 160,000 lbs/hr. During the quarter
ended March 31, 1998, steam revenues were reduced to zero because the annual
equivalent was not exceeded and an annual true-up of $0.2 million in favor of
General Electric was recorded. During the quarter ended March 31, 1997 steam
revenues were approximately $0.1 million, which includes an annual true-up of
$0.9 million in favor of General Electric. The decrease in steam revenues
during the quarter ended March 31, 1998 was primarily due to lower steam
demand. During the quarter ended March 31, 1998 approximately 385.9 million
pounds of steam were delivered as compared to approximately 506.3 million
pounds for the corresponding period in the prior year.
Gas resale revenues for the quarter ended March 31, 1998 were approximately
$2.0 million on sales of approximately 0.9 million MMBtu's as compared to
$1.4 million on sales of approximately 0.5 million MMBtu's for the
corresponding period in the prior year. The increase in gas resale revenues
was primarily due to lower dispatch of Unit 1 offset by lower natural gas
resale prices, which resulted in higher volumes of natural gas becoming
available for resale at lower prices. The decrease in natural gas resale
prices during the quarter ended March 31, 1998 generally resulted from more
moderate temperatures in the Northeast region as compared to the colder
temperatures, which caused an increase in the demand for natural gas during
the corresponding period in the prior year. The Partnership enters into gas
resales during periods when Units 1 and 2 are not operating at full capacity.
Cost of revenues for the quarter ended March 31, 1998 were approximately
$28.1 million on purchases of 6.9 million MMBtu's as compared to $31.3
million on purchases of 6.9 million MMBtu's for the corresponding period in
the prior year. The largest component of the decrease for the quarter ended
March 31, 1998 was fuel costs, which decreased $3.2 million from the prior
year. The decrease in the cost of fuel was primarily due to a decrease in
contract firm fuel rates from lower index fuel prices and rate decreases
under the firm transportation contracts. During the quarter ended March 31,
1998, firm fuel purchases from suppliers were comparable to the corresponding
period in the prior year.
Total other operating expenses for the quarter ended March 31, 1998 was
approximately $1.4 million as compared to $1.6 million for the corresponding
period in the prior year. The decrease in other operating expenses is
primarily due to a decrease in other general and administrative expenses.
8
<PAGE>
Net interest expense for the quarter ended March 31, 1998 of approximately
$8.2 million was comparable to the corresponding period in the prior year.
Liquidity and Capital Resources
Net cash flows provided by operating activities increased from approximately
$14.3 million for the quarter ended March 31, 1997 to $15.6 million for the
quarter ended March 31, 1998. The increase in net cash flows provided by
operating activities is primarily due to the increase in net income and
normally recurring changes in cash receipts and disbursements within the
Partnership's operating asset and liability accounts during the quarter ended
March 31, 1998.
Net cash flows used in investing activities for the quarter ended March 31,
1998 was approximately $12.1 million as compared to $16.1 million for the
corresponding period in the prior year. Net cash flows used in investing
activities primarily represent monies deposited into funds created pursuant
to the Partnership's Depositary and Disbursement Agreement, administered by
Bankers Trust Company, as depositary agent (the "Funds"). Monies deposited
into the Funds during the quarter ended March 31, 1998 primarily represent
monies set aside for interest payments to Bondholders scheduled for June 26,
1998. Monies deposited into the Funds during the quarter ended March 31,
1997 primarily represent monies set aside for interest and principal payments
to Bondholders scheduled for June 26, 1997.
There were no net cash flows associated with financing activities during the
quarter ended March 31, 1998. Net cash flows used in financing activities
for the quarter ended March 31, 1997 of $17,000 represent a payment to
General Electric pursuant to the Steam Sales Agreement.
The Partnership has entered into a Master Restructuring Agreement (as amended
on March 31, 1998, April 21, 1998, April 30, 1998 and May 7, 1998, the "MRA")
dated July 9, 1997 among Niagara Mohawk, the Partnership and certain other
non-utility power generators selling electricity to Niagara Mohawk (the
"Settling IPP's"). For a description of certain applicable provisions of the
MRA and related transactions see "Unit 1 Restructuring" below. On May 7,
1998, the Partnership, together with other Settling IPP's, agreed with
Niagara Mohawk that certain third party conditions to the obligations of the
Settling IPP's under the MRA have been either satisfied or waived, excluding
the receipt of certain regulatory approvals and, in the case of the
Partnership, the satisfaction of certain standards and procedures under the
Partnership's Trust Indenture for consummation of the transactions
contemplated by the MRA. If the Partnership and Niagara Mohawk proceed to
complete the transactions provided under the MRA, which completion remains
subject to a number of significant contingencies, the existing Niagara Mohawk
Power Purchase Agreement will be amended and restated to modify the basis on
9
<PAGE>
which the Partnership makes sales of the electrical capacity and output of
Unit 1 (the "Amended and Restated Unit 1 Agreement"). Management of the
Partnership believes that, based on those facts and circumstances currently
known, and certain assumptions which management believes to be reasonable,
proceeding with the Amended and Restated Unit 1 Agreement is not expected to
have a material adverse impact on the Partnership's future operating results
and cash flows from operations. Should this conclusion change for any reason
prior to completion of the MRA transactions, the Partnership does not expect
that it would be able to satisfy the standards set forth in its Trust
Indenture and would, therefore, not be obligated to proceed further under the
MRA. For the quarter ended March 31, 1998, capacity and energy sales to
Niagara Mohawk accounted for approximately 20.0% of total project revenues.
Con Edison by a letter dated September 19, 1994 claimed the right to acquire
that portion of Unit 2's firm natural gas supply not used in operating Unit
2, when Unit 2 is dispatched off-line or at less than full capability. The
Con Edison Power Purchase Agreement contains no express language granting Con
Edison any rights with respect to such excess natural gas. Nevertheless, Con
Edison has argued that, since payments under the contract include fixed fuel
charges which are payable whether or not Unit 2 is dispatched on-line, Con
Edison is entitled to take delivery of any excess natural gas. The
Partnership vigorously disputes the position adopted by Con Edison, based
notably on the absence of any contractual provision according Con Edison the
claimed rights but also on the fact that the Partnership has assumed the risk
under the Con Edison Power Purchase Agreement that the fuel charges payable
by Con Edison are insufficient to cover the costs actually incurred by the
Partnership. By a letter dated May 23, 1995, Con Edison indicated its
intention to pursue the claim asserted in the September 19, 1994 letter. In
the May 23, 1995 letter, Con Edison reserved the right to claim 100% of the
margins derived from the sales of Unit 2's firm natural gas supply not used
in operating Unit 2 (non-plant gas sales) and requested that the Partnership
reduce the monthly amount invoiced to Con Edison by 50% of a calculated value
of the non-plant gas sales. The Partnership strenuously objected to Con
Edison's contentions and, at a meeting between the Partnership and Con
Edison, Con Edison agreed to continue not to deduct any amount attributable
to non-plant gas sales from payments made upon monthly invoices but stated it
would do so under protest, pending further discussions between the parties.
Since the commencement of commercial operations of Unit 2, the Partnership
made and continues to make, from time to time, excess gas lay-off sales from
Unit 2's gas supply. The Partnership does not intend to adjust the monthly
invoices issued to Con Edison and continues to assert that Con Edison is not
entitled to any revenues or margins derived from non-plant gas sales. In the
event Con Edison were to pursue its asserted claim, the Partnership would
expect to pursue all available legal remedies, but there can be no certainty
that the outcome of such remedial action would be favorable to the
Partnership or, if favorable, would provide for the Partnership's full
recovery of its damages.
10
<PAGE>
The Partnership's cash flows from the sale of electric output would be
materially and adversely affected if Con Edison were to prevail in its claim
to Unit 2's excess natural gas volumes and the related margins.
Future operating results and cash flows from operations are dependent on,
among other things, the performance of equipment and processes as expected,
level of dispatch, fuel deliveries and price as contracted and the receipt of
certain capacity and other fixed payments. A significant change in any of
these factors could have a material adverse effect on the results for the
Partnership.
The Partnership believes that based on current conditions and circumstances
it will have sufficient liquidity available provided by cash flows from
operations to fund existing debt obligations and operating costs.
Unit 1 Restructuring
In October 1995, Niagara Mohawk filed its "Power Choice" proposal with the
New York State Public Service Commission ("NYPSC"). On October 12, 1995,
Niagara Mohawk filed a Report on Form 8-K with the Securities and Exchange
Commission explaining the Power Choice proposal (the "Power Choice
Statement"). In the Power Choice Statement, Niagara Mohawk described a
number of related proposals to restructure the utility's business, including
the reorganization of its assets and the renegotiation of its contracts with
generators which, like the Partnership, are not regulated as utilities
("non-utility generators"). The Power Choice Statement proposed several
alternative ways to restructure agreements with non-utility generators,
including the exercise by Niagara Mohawk of the power of eminent domain to
take possession of the projects of non-utility generators with whom
negotiations were unsuccessful. Following the filing of the Power Choice
proposal with the NYPSC, the Partnership joined with other non-utility gen
erators selling power to Niagara Mohawk to commence negotiations concerning a
joint settlement that would result in the termination or restructuring of
their respective power purchase agreements.
On July 9, 1997, Niagara Mohawk, the Partnership and the Settling IPP's
representing, in the aggregate, twenty-nine power purchase agreements,
entered into the MRA. On October 11, 1997, Niagara Mohawk filed its Power
Choice settlement, which incorporates the terms of the MRA, with the NYPSC.
On February 24, 1998, the NYPSC approved Niagara Mohawk's Power Choice
settlement proposal, including the implementation of the MRA.
11
<PAGE>
Master Restructuring Agreement. The MRA, if consummated, includes the
following principal features: (i) Niagara Mohawk will pay to those Settling
IPP's terminating their respective power purchase agreements (which does not
include the Partnership) a combination of cash payments and shares of Niagara
Mohawk Common Stock, (ii) certain of the power purchase agreements (including
the existing Niagara Mohawk Power Purchase Agreement with the Partnership)
will be amended and restated, such that the Settling IPP's rights on a
going-forward basis will include the right to receive (or the obligation to
pay) indexed electric rate swap payments and the right to "put" a defined
quantity of electricity to Niagara Mohawk until a power exchange is
established in Niagara Mohawk's service territory, and (iii) substantially
all of the Settling IPP's (including the Partnership) will receive, as
compensation for certain estimated costs identified in connection with the
restructuring of their gas supply and transportation arrangements (the "gas
mitigation costs"), cash payments derived from certain fixed price electric
rate swap contracts to be entered into by Niagara Mohawk with one or more
counterparties, or alternatively, directly from Niagara Mohawk.
Implementation of the MRA is subject to a number of significant conditions,
certain of which have not yet been satisfied, including without limitation
the receipt of all regulatory approvals, the satisfaction of certain
standards under the Partnership's Trust Indenture relating to the absence of
material adverse changes or receiving any required approval of bondholders or
other creditors, and the receipt by Niagara Mohawk of all necessary approvals
from its board of directors and shareholders.
On May 7, 1998, pursuant to the MRA, the Partnership delivered to Niagara
Mohawk written notice that, with certain exceptions, the conditions to the
Partnership's obligations under the MRA which involve the consent of third
parties (other than regulatory approvals) and the modification of existing
contractual arrangements with third parties had been either satisfied or were
being waived by the Partnership. The specified exceptions, satisfaction of
which continue to be conditions to the Partnership's obligation to undertake
the transactions contemplated by the MRA, include (i) receipt of the approval
of the Partnership's bondholders to the Unit 1 restructuring or a
determination by the Partnership that it will undertake the Unit 1
restructuring without a vote of its bondholders as permitted by the
Partnership's Trust Indenture (the "Indenture Approval") and (ii) upon the
request of the Partnership, mutually satisfactory renegotiation of certain
provisions of the proposed Amended and Restated Unit 1 Agreement to be
entered into by Niagara Mohawk and the Partnership relating to the dependable
maximum net capability ("DMNC") of Unit 1 (described below). Should Niagara
Mohawk and the Partnership satisfy all of the conditions to effectuating the
transactions contemplated by the MRA with respect to the Partnership, Niagara
Mohawk may nevertheless terminate the MRA if Niagara Mohawk determines that,
as a result of the failure to satisfy the conditions of the MRA by other
independent power producers, the benefits anticipated to be received by
Niagara Mohawk pursuant to the MRA have been materially and adversely
affected. Further, final implementation of the MRA is conditioned upon
Niagara Mohawk's successful completion of financing required to fund certain
of its payment obligations under agreements to implement the MRA. Although
the MRA establishes June 30, 1998 as the closing date for the transactions
with the other Settling IPP's (the "IPP Closing"),
12
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pursuant to an amendment to the MRA, the Partnership may extend the time for
securing the Indenture Approval and closing the MRA transactions as to the
Partnership (the "Selkirk Closing" ) until August 31, 1998. If the
Partnership has not obtained the Indenture Approval by such date, the MRA
will terminate as to the Partnership.
Unless the MRA has been terminated as to the Partnership on or before the IPP
Closing, on such date the Partnership will be obligated to fund certain
payments related to the agreed allocation among the Settling IPP's of certain
costs and benefits under the MRA and the allocated gas mitigation costs.
Currently, the Partnership estimates that these payments will total $2.2
million. If the MRA is subsequently terminated as to the Partnership,
Niagara Mohawk is contractually obligated to reimburse the Partnership for
this amount within two business days of such termination. If the Selkirk
Closing is consummated, the Partnership will be entitled to receive, as its
net share of the agreed allocation among IPP's for certain adjustments and
gas mitigation costs, a cash payment currently estimated to total $10.4
million (representing net receipts to the Partnership of approximately $8.2
million).
Amended and Restated Unit 1 Agreement. Following the execution and delivery
of the MRA, the Partnership and Niagara Mohawk commenced negotiation of the
Amended and Restated Unit 1 Agreement. In accordance with the terms of the
MRA, the format for the negotiated Amended and Restated Unit 1 Agreement
consists of an indexed electric rate ISDA swap contract (the "Swap Contract")
and a power put agreement (the "Put Contract") which are intended
collectively to amend and restate the existing Unit 1 Power Purchase
Agreement with Niagara Mohawk. The Partnership and Niagara Mohawk have
reached definitive agreement on the detailed terms of the Swap Contract and
the Put Contract, but the effectiveness of these agreements is subject to the
closing of the MRA transactions as to the Partnership. The following
discussion is intended to present only the broad outlines of the principal
terms included in the current version of the Amended and Restated Unit 1
Agreement.
The Swap Contract portion of the Amended and Restated Unit 1 Agreement
involves only cash payment obligations and does not require the physical
production or delivery of Unit 1 electrical capacity or output. During the
ten-year term of the Swap Contract, one party will be required to pay to the
other party, on a monthly basis, the difference between the Fixed Payments
and the Floating Payments (each defined below) for such month. If the Fixed
Payments exceed the Floating Payments, Niagara Mohawk will pay the difference
to the Partnership. If the Floating Payments exceed the Fixed Payments, the
Partnership will pay the difference to Niagara Mohawk. These payment
obligations are determined solely on the basis of the factors referenced
below and will not be affected by whether Unit 1 is operated.
13
<PAGE>
The Fixed Payment and the Floating Payment are each calculated on the basis
of a notional contract quantity, expressed in megawatts ("MW"), which is
established at 37 MW in the first contract year, escalating in annual
increments to 55 MW in the tenth contract year. The "Fixed Payment" is
determined by multiplying the applicable monthly contract quantity by an
indexed contract price (the "Contract Price"). The Contract Price is fixed
for the first contract year and the second contract year and thereafter is
determined by the application of a formula which takes into account a
specified heat rate, changes in a consumer price index and a gas pricing
component based on the Canadian spot gas price at Empress, Alberta (the
"Empress spot price"). The Contract Price has been designed to reflect
generally the Partnership's principal cost components for Unit 1 operations.
The Fixed Payment is subject to downward adjustment if at any time during the
term of the Swap Contract the tested DMNC of Unit 1 falls below the notional
contract quantity (the "DMNC Adjustment").
The "Floating Payment" is determined by multiplying the applicable monthly
contract quantity by a market price that will initially equal Niagara
Mohawk's short term avoided energy and capacity costs as stated in its tariff
for power purchases from "qualifying facilities" within the meaning of the
Public Utility Regulatory Policies Act of 1978, as amended (the "Proxy-Market
Price"). At such time as an independent system operator and power exchange
within New York ("ISO/power exchange") is established and fully functioning,
the market price used in determining the Floating Payment will equal the day
ahead locational based market price published by the ISO/power exchange (the
"Market Price"), unless the parties agree to continue to use the Proxy-Market
Price. The Floating Payment, like the Fixed Payment, is subject to the DMNC
Adjustment. After the establishment of the ISO/power exchange, and only if a
separate market for capacity is established by ISO/power exchange capacity
auctions, the Floating Payment is subject to increase by an amount equal to
the market price paid to sellers of electrical capacity at the Partnership's
delivery point (the "Market Capacity Price"), multiplied by the weighted
average capacity associated with the notional contract quantity.
The Put Contract portion of the Amended and Restated Unit 1 Agreement, like
the Swap Contract, has a term of ten years. The central feature of the Put
Contract, however, which is the ability of the Partnership to require Niagara
Mohawk to purchase energy, terminates at the time the ISO/power exchange is
established and fully functioning. Upon prior notice to Niagara Mohawk, the
Partnership may put energy and associated capacity to Niagara Mohawk for
periods ranging from one hour to one month, up to 105% of the then applicable
monthly contract quantity (which parallels the Swap Contract). The energy
and capacity put to Niagara Mohawk under the Put Contract may be produced by
Unit 1, Unit 2 or any other source. The price to be paid by Niagara Mohawk
for energy and associated capacity purchased by it upon the exercise of the
Partnership's put option will be the Proxy-Market Price or the Market Price,
and, if applicable, the Market Capacity Price.
14
<PAGE>
If the Partnership elects not to exercise its option to put energy and
associated capacity to Niagara Mohawk, it may sell such energy and capacity
to third parties, but only if the Partnership first offers Niagara Mohawk the
opportunity to purchase such energy and capacity at the Proxy-Market Price or
the Market Price, and, if applicable, the Market Capacity Price, and Niagara
Mohawk declines. The Partnership has the right to sell energy and associated
capacity of Unit 1 in excess of the applicable monthly contract quantity to
third parties without giving Niagara Mohawk a right of first refusal.
If and when the Swap Contract and Put Contract go into effect, Niagara Mohawk
will cease to have the right to direct dispatch of Unit 1, and the
Partnership's decision as to whether, and at what capacity, to run Unit 1
will be largely based on market conditions then in effect. The market and
pricing risks associated with such operation during the first ten years,
however, will be mitigated by the payment obligations of Niagara Mohawk under
the Swap Contract. The Partnership's existing Unit 1 interconnection
agreement with Niagara Mohawk will remain in force and effect following the
Unit 1 restructuring, as will the existing Unit 2 interconnection and
transmission agreements with Niagara Mohawk.
Unit 1 Gas Supply and Transportation. Following the execution of the MRA,
the Partnership commenced negotiations with its Unit 1 gas supplier,
Paramount Resources Ltd. ("Paramount"), to effect certain modifications to
the existing Unit 1 Gas Purchase Contract with Paramount necessary to align
the principal terms of the Unit 1 gas supply with the proposed Amended and
Restated Unit 1 Agreement. On May 6, 1998, the Partnership and Paramount
executed a Second Amended and Restated Gas Purchase Contract (the "Amended
Paramount Contract"), which will take effect on the later to occur of the
date Paramount and the Partnership obtain any necessary regulatory approvals
for the amendment and the date of the Selkirk Closing, when the Unit 1
restructuring under the MRA is consummated.
Under the Amended Paramount Contract, the following key volume, price and
dedicated reserve terms (among others) would be modified as follows: (i) the
maximum daily quantity of natural gas which the Partnership is entitled to
purchase would be reduced from 23,000 Mcf to 16,400 Mcf; (ii) the commodity
charge component of the contract price would cease to be a base price
escalated with Niagara Mohawk's fossil fuel index but would instead reflect
the current Empress spot price (the same indexed price as is used to
determine the Contract Price under the Swap Contract portion of the Amended
and Restated Unit 1 Agreement); (iii) the gas price renegotiation/arbitration
provisions in the existing Paramount Contract would be eliminated; (iv)
Paramount would have increased flexibility to manage the reserves dedicated
to the Amended Paramount Contract so long as Paramount is meeting its
delivery obligations for the volumes nominated by the Partnership; and (v) on
any day on which Paramount fails to meet its delivery obligations for
Partnership nominations, Paramount would be obligated to make its
transportation on NOVA Corporation of Alberta available to the Partnership to
the extent of the shortfall.
15
<PAGE>
The Partnership has also agreed with Paramount that, in conjunction with the
effectiveness of the Amended Paramount Contract, the Partnership will
permanently assign to Paramount or its nominee 6,000 Mcf of the Partnership's
daily transportation capacity rights under the Partnership's firm gas
transportation contract for Unit 1 with TransCanada Pipelines Limited.
Indenture Approval. The Partnership's Trust Indenture, dated May 1, 1994,
establishes certain standards which must be satisfied and procedures which
must be completed in order for the Partnership to modify its existing project
agreements in connection with the proposed Unit 1 restructuring. These
standards and procedures include without limitation certain findings with
respect to the absence of a "Material Adverse Change", which must be
confirmed in writing by the "Independent Engineer" and the "Gas Consultant",
in each case as such terms are defined in the Trust Indenture.
Management of the Partnership has evaluated the proposed Unit 1 restructuring
and determined that, based on currently known facts and circumstances, and
certain assumptions which it believes to be reasonable, consummation of the
Unit 1 restructuring is in the best interests of the Partnership and could
not reasonably be expected to result in a Material Adverse Change (as defined
in the Trust Indenture). Currently, management is engaged in consultations
with the Independent Engineer, the Gas Consultant and other advisors for the
purpose of confirming its determinations and carrying out the approval and
certification procedures required by the Trust Indenture for effecting the
necessary project agreement modifications. In the event that at any time
prior to the Selkirk Closing the Partnership should alter its determination
of the absence of Material Adverse Change for any reason, it would not expect
to consummate the Unit 1 restructuring. In the event that the Partnership
were to be unable to satisfy the standards and complete the procedures for
amending project agreements without bondholder consent which are contained in
the Trust Indenture, the Partnership could determine to seek bondholders'
consent to the adoption of a supplemental indenture authorizing the Unit 1
restructuring.
At this time the Partnership is unable to predict whether it will be
successful in obtaining the required Indenture Approval within the time
limits established under the MRA. Further, the Partnership expresses no
opinion with respect to the likelihood that all of the other conditions to
implementation of the MRA will be met, nor with respect to the viability of
Niagara Mohawk's proposed alternatives should the implementation of the MRA
not be completed. Such proposed alternatives include Niagara Mohawk's
proposal in the context of the Power Choice Statement to take possession of
independent power projects through the power of eminent domain and to
thereafter sell such projects or Niagara Mohawk's position that it has not
ruled out the ultimate possibility of a filing for restructuring under
Chapter 11 of the U.S. Bankruptcy Code as set forth in the Power Choice
Statement. Nevertheless, in the absence of agreement on a definitive
restructured power purchase agreement, the Partnership continues to believe
16
<PAGE>
that the existing Niagara Mohawk Power Purchase Agreement is a valid and
binding contract with Niagara Mohawk.
Previously, Standard & Poor's placed the Bonds on creditwatch "with negative
implications," based in part on its analysis of the public reports filed by
Niagara Mohawk and the Partnership, respectively, and its belief that the
restructuring has the potential to erode cash flow coverage derived from
long-term contracts supporting the Bonds. To date Standard & Poor's has not
changed its outlook on the Bonds. Additionally, as of the date of this
report, Moody's Investors Service has not changed its rating or its previous
"negative outlook" on the Bonds based on the developments with Niagara
Mohawk.
Year 2000
Management of the Partnership is conducting a review of its computer systems
to identify the systems that could be affected by the new millennium. The
year 2000 may pose problems in software applications because many computer
systems and applications currently use two-digit date fields to designate a
year. As the century date occurs, date sensitive systems may recognize the
year 2000 as 1900 or not at all. This potential inability to recognize or
properly treat the year 2000 may cause systems to process financial or
operational information incorrectly. Management has not yet determined
which, if any, systems may be affected and, if affected, the extent of any
potential disruption in operations and the resulting potential impact on the
Partnership's ability to generate and deliver electricity or steam.
Management has begun to develop and, if required, implement a plan to remedy
any potential problems prior to the year 2000. Management expects to
finalize this plan, if required, and estimate any potential expenses to i
mplement such plan, in 1998. Management has not yet assessed expenses
related to year 2000 compliance or the potential impacts of this matter.
17
<PAGE>
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
- -----------------------------------------
(A) Exhibits
Exhibit No. Description Page No.
----------- ----------- --------
27 Financial Data Schedule
(For electronic filing purposes only)
(B) Reports on Form 8-K
Not Applicable.
Omitted from this Part II are items which are not applicable or to which the
answer is negative for the periods covered.
18
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized.
SELKIRK COGEN PARTNERS, L.P.
Date: May 15, 1998 /s/ JMC SELKIRK, INC.
--------------------------
Name: General Partner
Date: May 15, 1998 /s/ JOHN R. COOPER
--------------------------
Name: John R. Cooper
Title: Senior Vice President and
and Chief Financial Officer
19
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized.
SELKIRK COGEN FUNDING
CORPORATION
Date: May 15, 1998 /s/ JOHN R. COOPER
--------------------------
Name: John R. Cooper
Title: Senior Vice President and
and Chief Financial Officer
20
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