CONFORMED COPY WITH EXHIBITS
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 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) 788-3000
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) or 12 (g) OF THE ACT:
None
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No __
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. X
As of March 30, 1999, there were 10 shares of common stock of Selkirk Cogen
Funding Corporation, $1 par value outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
None
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TABLE OF CONTENTS
Page
PART I
Item 1. Business............................................... 3
Item 2. Properties............................................. 17
Item 3. Legal Proceedings...................................... 18
Item 4. Submission of Matters to a Vote of Security Holders.... 19
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.................................. 20
Item 6. Selected Financial Data................................ 20
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................. 21
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk ......................................... 33
Item 8. Financial Statements and Supplementary Data............ 33
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.................. 33
PART III
Item 10. Directors and Executive Officers of the Registrant..... 34
Item 11. Executive Compensation................................. 35
Item 12. Security Ownership of Certain Beneficial Owners and
Management........................................... 36
Item 13. Certain Relationships and Related Transactions......... 37
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K.......................................... 38
Signatures............................................................... 51
2
PART I
ITEM 1. BUSINESS
General
Selkirk Cogen Partners, L.P. (the "Partnership") is a Delaware limited
partnership that owns a natural gas-fired cogeneration facility in the Town of
Bethlehem, County of Albany, New York (together with associated materials,
ancillary structures and related contractual and property interests, the
"Facility"). The Partnership was formed in 1989, and its sole business is the
ownership, operation and maintenance of the Facility. The Partnership has
long-term contracts to sell electric capacity and energy produced by the
Facility to Niagara Mohawk Power Corporation ("Niagara Mohawk") and Consolidated
Edison Company of New York, Inc. ("Con Edison") and steam produced by the
Facility to GE Plastics, a core business of General Electric Company ("General
Electric"). The Partnership operates as a single business segment.
Selkirk Cogen Funding Corporation (the "Funding Corporation"), a Delaware
corporation, was organized in April 1994 to serve as a single-purpose financing
subsidiary of the Partnership. All of the issued and outstanding capital stock
of the Funding Corporation is owned by the Partnership.
The Partnership and the Funding Corporation's principal executive offices
are located at One Bowdoin Square, Boston, Massachusetts 02114. The telephone
number is (617) 788-3000.
The Partnership
The managing general partner of the Partnership is JMC Selkirk, Inc. ("JMC
Selkirk" or the "Managing General Partner"). The other general partner of the
Partnership (together with JMC Selkirk, the "General Partners") is Cogen
Technologies Selkirk GP, Inc. ("Cogen Technologies GP"). The limited partners of
the Partnership (the "Limited Partners," and together with the General Partners,
the "Partners") are JMC Selkirk, PentaGen Investors, L.P., formerly known as
JMCS I Investors, L.P. ("Investors"), EI Selkirk, Inc. ("EI Selkirk") and Cogen
Technologies Selkirk, LP, Inc. ("Cogen Technologies LP").
The Managing General Partner is responsible for managing and controlling
the business and affairs of the Partnership, subject to certain powers which are
vested in the management committee of the Partnership (the "Management
Committee") under the Partnership Agreement. Each General Partner has a voting
representative on the Management Committee, which, subject to certain limited
exceptions, acts by unanimity. Thus, the General Partners, and principally the
Managing General Partner, exercise control over the Partnership.
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JMCS I Management, Inc. ("JMCS I Management"), an affiliate of the Managing
General Partner, is acting as the project management firm (the "Project
Management Firm") for the Partnership, and as such is responsible for the
implementation and administration of the Partnership's business under the
direction of the Managing General Partner. Upon the occurrence of certain events
specified in the Partnership Agreement, Cogen Technologies GP may assume the
powers and responsibilities of the Managing General Partner and of the Project
Management Firm. Under the Partnership Agreement, each General Partner other
than the Managing General Partner may convert its general partnership interest
to that of a Limited Partner.
JMC Selkirk is an indirect, wholly owned subsidiary of Beale Generating
Company ("Beale", formerly known as J. Makowski Company, Inc ("JMCI")). Beale
owns interests in gas-fired electric generating facilities and natural gas
supply and transportation projects. On August 25, 1994, Beale, owned through
affiliation by Bechtel Generating Company, Inc. ("Bechtel"), a subsidiary of
Bechtel Enterprises and PG&E Generating Company ("PG&E Generating"), a
subsidiary of PG&E Enterprises, acquired the stock of JMCI. On May 4, 1998, PG&E
Corporation ("PG&E Corp."), a holding company, completed a restructuring which
involved the insertion of two new wholly-owned subsidiaries of PG&E Corp.,
namely U.S. Generating Company, LLC ("USGen Company") and USGen Power Group, LLC
("USGen Power") between Beale and PG&E Generating. As a consequence of the
restructuring, the Partnership continues to be indirectly wholly owned by Beale,
which is now partly owned by USGen Power. USGen Power is wholly owned by USGen
Company, which in turn is wholly-owned by PG&E Generating. On October 15, 1998,
Beale merged with and into JMCI, with JMCI being the surviving corporation.
Concurrently, JMCI changed its name to Beale Generating Company. On October 20,
1998, Cogentrix Eastern America, Inc., ("Cogentrix"), a subsidiary of Cogentrix
Energy, Inc., as part of a larger transaction between Cogentrix and Bechtel,
acquired Bechtel's ownership interest in Beale.
JMCS I Management is an indirect, wholly-owned subsidiary of PG&E
Generating. On March 1, 1998, PG&E Generating contributed 100% of the stock of
JMCS I Management to USGen Company, which in turn transferred the stock to its
subsidiary, USGen Services, LLC.
Investors is a Delaware limited partnership consisting of JMCS I Holdings,
Inc., JMC Selkirk, Inc. (each an affiliate of Beale) and TPC Generating, Inc.
Cogen Technologies GP and Cogen Technologies LP are each affiliates of RCM
Holdings, Inc. ("RCM", formerly known as Cogen Technologies, Inc.).
EI Selkirk is a wholly-owned subsidiary of GPU International, Inc. ("GPUI",
formerly known as Energy Initiatives, Inc.) which in turn is a wholly-owned
subsidiary of GPU, Inc. (formerly known as General Public Utilities
Corporation), a registered electric utility holding company under the Public
Utility Holding Company Act of 1935, as amended ("PUHCA").
4
The Funding Corporation
The Funding Corporation was established for the sole purpose of issuing
$165,000,000 of 8.65% First Mortgage Bonds Due 2007 (the "Old 2007 Bonds") and
$227,000,000 of 8.98% First Mortgage Bonds Due 2012 (the "Old 2012 Bonds," and
collectively with the Old 2007 Bonds, the "Old Bonds") for its own account and
as agent acting on behalf of the Partnership pursuant to a Trust Indenture among
Funding Corporation, the Partnership and Bankers Trust Company, as trustee (the
"Indenture"). A portion of the proceeds from the sale of the Old Bonds was
loaned to the Partnership in connection with financing its outstanding
indebtedness and the remaining proceeds were loaned to the Partnership (the
total amount of such extensions of credit, the "Partnership Loans").
Subsequently, in November 1994, the Funding Corporation and the Partnership
offered to exchange (i) $165,000,000 of 8.65% First Mortgage Bonds Due 2007,
Series A (the "New 2007 Bonds") for a like principal amount of Old 2007 Bonds,
and (ii) $227,000,000 of 8.98% First Mortgage Bonds Due 2012, Series A (the "New
2012 Bonds," and collectively with the New 2007 Bonds, the "New Bonds", and the
New Bonds together with the Old Bonds, the "Bonds") for a like principal amount
of Old 2012 Bonds, respectively, with the holders thereof. On December 12, 1994,
the exchange of all of the Old Bonds for the New Bonds was completed, and none
of the Old Bonds remain outstanding. The obligations of the Funding Corporation
in respect of the Bonds are unconditionally guaranteed by the Partnership (the
"Guarantee").
The Bonds, the Partnership Loans and the Guarantee are not guaranteed by,
or otherwise obligations of, the Partners, Beale Generating Company, TPC
Generating, Inc., PG&E Enterprises, Cogentrix Energy, Inc., Cogen Technologies,
GPUI or any of their respective affiliates, other than the Funding Corporation
and the Partnership. The obligations of the Partnership under the Partnership
Loans and the Guarantee are secured by, among other things, a pledge by the
General Partners of their respective general partnership interests in the
Partnership and pledges by the shareholders of JMC Selkirk and of Cogen
Technologies GP of the outstanding capital stock of each such General Partner.
The Facility and Certain Project Contracts
The Facility
The Facility is located on an approximately 15.7 acre site leased from
General Electric adjacent to General Electric's plastic manufacturing plant (the
"GE Plant") in the Town of Bethlehem, County of Albany, New York (the "Facility
Site"). The Facility is a natural gas-fired cogeneration facility which has a
total electric generating capacity in excess of 345 megawatts ("MW") with a
maximum average steam output of 400,000 pounds per hour ("lbs/hr"). The Facility
consists of one unit ("Unit 1") with an electric generating capacity of
approximately 79.9 MW and a second unit ("Unit 2") with an electric generating
capacity of approximately 265 MW. The Public Utilities Regulatory Policies Act
of 1978, as amended ("PURPA") defines a cogeneration facility as a facility
which produces electric energy and
5
forms of useful thermal energy (such as heat or steam), used for industrial,
commercial, heating or cooling purposes, through the sequential use of one or
more energy inputs. In the case of the Facility, the Facility uses natural gas
as its primary fuel input to produce electric energy for sale to Niagara Mohawk
and Con Edison and to produce useful thermal energy in the form of steam for
sale to General Electric for industrial purposes. The Facility is a
"topping-cycle cogeneration facility," which means that when the Facility is
operated in a combined-cycle mode, it uses natural gas or fuel oil to produce
electricity, and the reject heat from power production is then used to provide
steam to General Electric. Unit 1 and Unit 2 have been designed to operate
independently for electrical generation, while thermally integrated for steam
generation, thereby optimizing efficiencies in the combined performance of the
Facility. A properly designed and constructed cogeneration facility is able to
convert the energy contained in the input fuel source to useful energy outputs
more efficiently than typical utility plants. The Facility has been certified as
a qualifying facility ("Qualifying Facility") in accordance with PURPA and the
regulations promulgated thereunder by the Federal Energy Regulatory Commission
("FERC").
Niagara Mohawk
The Partnership has a long term contract with Niagara Mohawk to sell
electric capacity and energy produced by Unit 1 to Niagara Mohawk. For the year
ended December 31, 1998, electric sales to Niagara Mohawk accounted for
approximately 20.5% of total project revenues.
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").
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. The Partnership entered into a Master Restructuring Agreement (as
amended on March 31, 1998, April 21, 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). On February 24, 1998, the NYPSC approved Niagara Mohawk's
Power Choice settlement proposal, including the implementation of the MRA.
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"). 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. Pursuant to the terms
6
of the MRA, the closing of the MRA transactions between the Partnership and
Niagara Mohawk was deferred until August 31, 1998.
On August 31, 1998 the Partnership and Niagara Mohawk consummated the
transactions contemplated by the Amended and Restated Niagara Mohawk Power
Purchase Agreement pursuant to the MRA. As contemplated by the MRA, on that date
(i) the Partnership notified Niagara Mohawk of the Partnership's determination
that the requirements of the Partnership's Trust Indenture, dated as of May 1,
1994 (the "Indenture"), with respect to the restructuring of certain project
contracts relating to the operation of Unit 1 of the Selkirk facility had been
satisfied; (ii) the Amended and Restated Power Purchase Agreement, dated as of
July 1, 1998, between the Partnership and Niagara Mohawk became effective; and
(iii) Niagara Mohawk made cash payments of approximately $10.3 million,
representing its net share of the agreed allocation among IPP's for certain
adjustments, into the Partnership's Project Revenue Fund maintained at Bankers
Trust Company, as Depositary Agent under the May 1, 1994 Deposit and
Disbursement Agreement. In addition, the Partnership delivered notices to
Paramount Resources Limited ("Paramount") and TransCanada Pipelines Limited
("TransCanada") that the Second Amended and Restated Gas Purchase Contract,
dated as of May 6, 1998, between the Partnership and Paramount, and the Amending
Agreement to Gas Transportation Contract, dated as of July 20, 1998, between the
Partnership and TransCanada had become effective. On September 16, 1998, the
Partnership filed a current report on Form 8-K disclosing the consummation on
August 31, 1998 of the transactions relating to the Amended and Restated Niagara
Mohawk Power Purchase Agreement and including the related Project documents as
exhibits.
On August 31, 1998, the Partnership received written notice from Standard &
Poor's Corporation ("S&P") that, after giving effect to the consummation of the
transactions contemplated by the Amended and Restated Niagara Mohawk Power
Purchase Agreement, S&P affirmed its "BBB-" rating of the Selkirk Cogen Funding
Corporation's Bonds and removed the rating from CreditWatch. On August 27, 1998,
the Partnership received written notice from Moody's Investors Service, Inc.
("Moody's") that, after giving effect to the Unit 1 Restructuring, Moody's
affirmed its "Baa3" rating of the Selkirk Cogen Funding Corporation's Bonds,
changed the outlook of the New 2007 Bonds from "negative" to "stable" and has
not changed its previous "negative outlook" with respect to the New 2012 Bonds.
Unit 1 commenced commercial operation on April 17, 1992 and through June
30, 1998 sold at least 79.9 MW of electric capacity and associated energy to
Niagara Mohawk under the original long-term contract that allowed Niagara Mohawk
to schedule Unit 1 for dispatch on an economic basis (the "Original Niagara
Mohawk Power Purchase Agreement"). The term of the Original Niagara Mohawk Power
Purchase Agreement was 20 years from the date of initial commercial operation of
Unit 1. On August 31, 1998 the Partnership and Niagara Mohawk executed an
Amended and Restated Power Purchase Agreement in conjunction with the
consummation of the transactions pursuant to the MRA. The term of the Amended
and Restated Niagara Mohawk Power Purchase Agreement is ten years from June 30,
1998 with the exception of Niagara Mohawk's transitional call rights discussed
below.
7
The Amended and Restated Niagara Mohawk Power Purchase Agreement provides
for a monthly contract payment ("Monthly Contract Payment") which is comprised
of four indexed pricing components: (i) a capacity payment, (ii) an energy
payment, (iii) a transportation payment and (iv) 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 (Sale Option and Call Option are
defined below). Niagara Mohawk will be obligated to pay the Partnership the
Monthly Contract Payment to the extent such number is positive, and, the
Partnership will be obligated to pay Niagara Mohawk the Monthly Contract 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 Niagara Mohawk Power Purchase 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 might be required to make to Niagara Mohawk during periods in
which actual market prices are high.
Market prices will be established by the marketplace in conjunction with
the Independent System Operator and/or Power Exchange ("ISO/PE") for each of 11
regions within New York State. Market prices will be determined based on daily
bids for quantity and price of energy as put by each willing supplier and will
establish the price at which each generator will be paid for energy supplied to
the region. Prior to the establishment of such market prices, the initial market
pricing for energy will be a proxy market price based on Niagara Mohawk's tariff
for power purchases from qualified facilities. Niagara Mohawk has the right
("Call Option") to call Unit 1's energy and capacity, up to the defined contract
quantities, during the period prior to the implementation by the ISO/PE of
market pricing (or 24 months, if earlier). 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").
Niagara Mohawk has 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 Niagara Mohawk Power Purchase 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
8
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.
The Partnership has two options for augmenting the fixed portions of the
Monthly Contract Payment. First, prior to the establishment of a fully
functioning ISO/PE, the Partnership will have the option to sell and deliver
energy and capacity to Niagara Mohawk up to a specified monthly contract
quantity, plus up to 5% of the monthly contract quantity ("Sale Option").
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. This energy and capacity may be
produced by Unit 1, Unit 2 or a third party source. Second, for any time period
during which the Partnership does not 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 annual contract volumes and notional contract quantities which are used
to calculate the fixed portions of the Monthly Contract Payment and establish
the maximum quantities of energy and capacity which Niagara Mohawk is obligated
to purchase or the Partnership is obligated to sell are set forth below.
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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
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Niagara Mohawk owns, operates and maintains interconnection facilities for
the combined Facility in accordance with separate Unit 1 and Unit 2
interconnection agreements. The Unit 1 interconnection facility is necessary to
effect the transfer of electricity produced at Unit 1 into Niagara Mohawk's
power grid at the delivery point adjacent to Unit 1. Since Unit 1 is
interconnected directly to Niagara Mohawk's power grid, no transmission services
are required for the delivery of power under the Amended and Restated Niagara
Mohawk Power Purchase Agreement. The Unit 2 interconnection facility is
necessary to effect the transfer of electricity produced at Unit 2 into Niagara
Mohawk's transmission system. Pursuant to a
9
transmission services agreement, Niagara Mohawk has agreed to provide firm
transmission services from Unit 2 to the point of interconnection between
Niagara Mohawk's transmission system and Con Edison's transmission system for a
period of 20 years from the date of the commencement of commercial operation of
Unit 2.
Con Edison
Unit 2 commenced commercial operation on September 1, 1994 and is selling
265 MW of electric capacity and associated energy to Con Edison under a
long-term contract that allows Con Edison to schedule Unit 2 for dispatch on an
economic basis (the "Con Edison Power Purchase Agreement," and together with the
Amended and Restated Niagara Mohawk Power Purchase Agreement, the "Power
Purchase Agreements"). The Con Edison Power Purchase Agreement has a term of 20
years from the date of commencement of commercial operation of Unit 2, subject
to a 10-year extension under certain conditions. The Con Edison Power Purchase
Agreement provides for four payment components: (i) a capacity payment, (ii) a
fuel payment, (iii) an Operations and Maintenance ("O&M") O&M payment and (iv) a
wheeling payment. The capacity payment, a portion of the fuel payment, a portion
of the O&M payment, and the wheeling payment are fixed charges to be paid on the
basis of plant availability to operate whether or not Unit 2 is dispatched
on-line. The variable portions of the fuel payment and O&M payment are payable
based on the amount of electricity produced by Unit 2 and delivered to Con
Edison. The total fixed and variable fuel payment is capped at a ceiling price
established (and is subject to adjustment) in accordance with the Con Edison
Power Purchase Agreement, and includes a component, which is equal to one-half
of the amount by which Unit 2's actual fixed and variable fuel commodity and
transportation costs differs from the ceiling price. For the year ended December
31, 1998 electric sales to Con Edison accounted for approximately 74.0% of total
project revenues.
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 that 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
10
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 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.
PG&E Energy Trading - Power, L.P.
To sell the excess capacity and energy generated from Units 1 and 2 and
other energy-related products, the Partnership entered into an enabling
agreement (the "Enabling Agreement") with PG&E Energy Trading - Power, L.P.
("PG&E Energy Trading"), an affiliate of JMC Selkirk. The Enabling Agreement
became effective on May 31, 1996, for a term of one year, and may be extended by
mutual agreement of the Partnership and PG&E Energy Trading. The Enabling
Agreement has previously been extended through May 31, 1999 and the Partnership
intends to renew the Enabling Agreement through May 2000. Under the Enabling
Agreement, the Partnership has the ability to enter into certain transactions
for the purchase and sale of electric capacity, electric energy and other
services at negotiated market prices. For each transaction, a transaction letter
is executed establishing the following terms and conditions: (i) the period of
delivery; (ii) the contract price; (iii) the delivery points; and (iv) the
contract quantity. For the year ended December 31, 1998 sales to PG&E Energy
Trading accounted for approximately 1.2% of total project revenues.
General Electric
Pursuant to a steam sales agreement with General Electric (the "Steam Sales
Agreement"), the Partnership is obligated to sell up to 400,000 lbs/hr of the
thermal output of Unit 1 and Unit 2 for use as process steam at the GE Plant
adjacent to the Facility for a term extending 20 years from the date of
commercial operations of Unit 2. The Partnership charges General Electric a
nominal price for steam delivered to General Electric in an amount up to the
annual equivalent of 160,000 lbs/hr during each hour in which the GE Plant is in
production (the "Discounted Quantity"). Steam sales in excess of the Discounted
Quantity are priced at General Electric's avoided variable direct cost, subject
to an "annual true-up" to ensure that General Electric receives the annual
equivalent of the Discounted Quantity at nominal pricing.
11
Pursuant to the Steam Sales Agreement, General Electric may implement
productivity or energy efficiency projects in its manufacturing processes,
including projects involving the production of steam within the GE Plant
commencing in 1996. General Electric implemented an energy efficiency project in
1997 that reduced the quantity of steam required by the GE Plant. Under the
energy efficiency project, General Electric anticipates managing its annual
average steam demand at 160,000 lbs/hr. If General Electric is able to manage
its annual average steam demand at 160,000 lbs/hr then the Partnership's steam
revenues would be reduced to the nominal amount General Electric is charged for
the annual equivalent of 160,000 lbs/hr. For the year ended December 31, 1998,
there were no steam sales to General Electric because General Electric managed
its annual average steam demand at approximately 160,000 lbs/hr. The energy
efficiency project does not relieve General Electric of its contractual
obligation to purchase the minimum thermal output necessary for the Facility to
maintain its status as a Qualifying Facility.
Unit 1 Gas Supply and Transportation
To supply natural gas needed to operate Unit 1, the Partnership entered
into a gas supply agreement with Paramount Resources Ltd. ("Paramount") on a
firm 365-day per year basis for a 15-year term beginning November 1, 1992 (the
"Original Paramount Contract"). On May 6, 1998, the Partnership and Paramount
executed a Second Amended and Restated Gas Purchase Contract (the "Amended
Paramount Contract") in conjunction with consummation of the transactions
pursuant to the MRA. Under the Amended Paramount Contract, the 15-year term
remained unchanged and the following key volume, price and dedicated reserve
terms (among others) have been modified as follows: (i) the maximum daily
quantity of natural gas which the Partnership is entitled to purchase has been
reduced from 23,000 Mcf to 16,400 Mcf; (ii) the commodity charge component of
the contract price is no longer a base price escalated with Niagara Mohawk's
fossil fuel index but instead reflects 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 Niagara Mohawk Power Purchase Agreement); (iii)
the gas price renegotiation/arbitration provisions in the existing Paramount
Contract have been eliminated; (iv) Paramount has 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 is obligated to make its
transportation on NOVA Corporation of Alberta available to the Partnership to
the extent of the shortfall. The Amended Paramount Contract requires Paramount
to maintain a level of recoverable reserves and deliverability from its
dedicated reserves through the term of the Amended Paramount Contract. Paramount
must demonstrate that it meets the recoverable reserves and deliverability
requirements in an annual report to the Partnership.
The Partnership entered into certain long-term contracts (collectively, the
"Unit 1 Gas Transportation Contracts") for the transportation of the Unit 1
natural gas volumes on a firm 365-day per year basis with TransCanada Pipelines
Limited ("TransCanada"), Iroquois Gas Transmissions System, L.P. ("Iroquois")
and Tennessee Gas Pipeline Company
12
("Tennessee"). Each of the Unit 1 Gas Transportation Contracts has a term of 20
years beginning November 1, 1992. Concurrent with the effectiveness of the
Amended Paramount Contract, the Partnership released 6,000 Mcf of the
Partnership's daily transportation capacity rights under the Partnership's firm
gas transportation contract for Unit 1 with TransCanada, in conjunction with
Paramount's acquiring 6,000 Mcf of daily transportation capacity rights on
TransCanada's pipeline system.
Unit 2 Gas Supply and Transportation
To supply natural gas needed to operate Unit 2, the Partnership entered
into gas supply agreements with Imperial Oil Resources, PanCanadian Petroleum
Limited and Producers Marketing Ltd. (formerly known as Atcor Limited)
(collectively, the "Unit 2 Gas Supply Contracts"), each on a firm 365-day per
year basis. Each of the Unit 2 Gas Supply Contracts has a 15-year term beginning
November 1, 1994. The Unit 2 gas suppliers have supported their delivery
obligations to the Partnership with their respective corporate warranties. The
Unit 2 Gas Supply Contracts are not supported by dedicated reserves. The
Partnership entered into certain long-term contracts (collectively, the "Unit 2
Gas Transportation Contracts") for the transportation of the Unit 2 natural gas
volumes on a firm 365-day per year basis with TransCanada, Iroquois and
Tennessee. Each of the Unit 2 Gas Transportation Contracts has a term of 20
years beginning November 1, 1994.
Fuel Management
The Partnership, through the Project Management Firm, manages the
Facility's fuel arrangements. The Partnership attempts to direct the supply and
transportation of natural gas to Unit 1 and Unit 2 under its long-term gas
supply and transportation contracts so as to have sufficient quantities of
natural gas available at the Facility to meet its scheduled operation. In
addition, the Partnership endeavors to take advantage of market opportunities,
as available, to resell its long-term, firm natural gas volumes at favorable
prices relative to their costs and relative to the cost of substitute fuels.
These opportunities include resales of excess natural gas supplies ("gas
resales") when Unit 1 or Unit 2 is dispatched off-line or at less than full
capacity, and "peak shaving" arrangements whereby the Partnership grants to
local distribution companies or other purchasers a call on a specified portion
of the Partnership's firm natural gas supply for a specified number of days
during the winter season. At such times as the purchaser calls upon the
Partnership's firm natural gas supply under a peak shaving arrangement, the
Partnership intends to operate on No. 2 fuel oil or, if available, interruptible
natural gas supplies. Typically, the Partnership's liability for failure to
deliver natural gas when called for under a peak shaving agreement is to
reimburse the purchaser for its prudently incurred incremental costs of finding
a replacement supply of natural gas. The Partnership attempts to schedule firm
gas transportation services to meet its requirements to fuel Unit 1 and Unit 2
and to meet its gas resales and peak shaving sales commitments without incurring
penalties for taking natural gas above or below amounts nominated for delivery
from the gas transporters. The Partnership supplements its contracted firm
transportation to the extent necessary to make gas resales and peak shaving
sales by entering
13
into agreements for interruptible transportation service. In managing Unit 2's
fuel arrangements, the Partnership, through the Project Management Firm, intends
to take into account that the Partnership must purchase a minimum annual
quantity of natural gas under the Unit 2 Gas Supply Contracts, subject to
true-up procedures, to avoid reduction of the maximum daily contract quantity
under such agreements.
Unit 1 and Unit 2 have the capability to operate on No. 2 fuel oil and are
able to switch fuel sources from natural gas to fuel oil, and back, without
interrupting the generation of electricity. The Partnership's air permit allows
the Facility to burn oil for a maximum of 2,190 hours per year (91.25 days per
year) at full capacity. The Partnership currently has on-site storage for
approximately one million gallons of fuel oil, a supply sufficient to run all
three gas turbines constituting the Facility for approximately one and a half
days at full capacity without refilling. The Partnership purchases fuel oil on a
spot basis. The Facility Site is approximately five miles from the Port of
Albany, New York, a major oil terminal area. In addition, several major oil
companies supply No. 2 fuel oil in the Albany area through leased storage or
throughput arrangements. Fuel oil is transported to the Facility by truck.
Customers/Competition
Niagara Mohawk is an investor-owned utility engaged in the production,
transmission and distribution of electrical energy and natural gas to customers
in upstate New York.
Con Edison is an investor-owned utility engaged in the production,
transmission and distribution of electrical energy and natural gas to New York
City (except portions of Queens) and most of Westchester County, New York.
PG&E Energy Trading, an affiliate of JMC Selkirk, is a wholly-owned
indirect subsidiary of PG&E Corp., engaged in selling energy and energy-related
products to power marketers, industrials, utilities and municipalities. PG&E
Energy Trading trades with United States and Canadian counterparties.
GE Plastics, a core business of General Electric, manufactures
high-performance engineered plastics used in applications such as automobiles,
housings for computers and other business equipment. GE Plastics sells worldwide
to a diverse customer base consisting mainly of manufacturers.
The demand for power in the United States traditionally has been met by
utility construction of large-scale electric generation projects under rate-base
regulation. PURPA removed certain regulatory constraints relating to the
production and sale of electric energy by eligible non-utilities and required
electric utilities to buy electricity from various types of non-utility power
producers under certain conditions, thereby encouraging companies other than
electric utilities to enter the electric power production market. Concurrently,
there has been a decline in the construction of large generating plants by
electric utilities. In addition to
14
independent power producers, subsidiaries of fuel supply companies, engineering
companies, equipment manufacturers and other industrial companies, as well as
subsidiaries of regulated utilities, have entered the non-utility power market.
The Partnership has a long-term agreement to sell electric generating capacity
and energy from the Facility to Con Edison. The Partnership has also executed an
Amended and Restated Power Purchase Agreement with Niagara Mohawk, which now
provides a hedge on energy costs to Niagara Mohawk while also providing for
recovery of capacity and other fixed payments over a term of ten years.
Therefore, the Partnership does not expect competitive forces to have a
significant effect on this portion of its business. Nevertheless, under each of
these agreements the Facility will typically be scheduled on an economic basis,
which takes into account the variable cost of electricity to be delivered by the
Unit compared to the variable cost of electricity available to the purchaser
from other sources. Accordingly, competitive forces may have some effect on the
Facility's dispatch levels. The Partnership cannot, at this time, determine what
effect, if any, the impact of such competitive sales will have on the
Partnership's financial condition or results of operation. See "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" for a discussion of the Facility's dispatch levels.
Seasonality
The Partnership's reliance on its power producer's customer and market
demand results in the Facility's dispatch being somewhat affected by
seasonality. Niagara Mohawk's residential customer demand peaks during the
colder winter months due to customer reliance on electric heat, and Con Edison's
commercial customer demand peaks during the warmer summer months due to customer
reliance on air conditioning in office buildings. In addition, the gas resale
market is also somewhat seasonal in nature, with the cold winter months tending
to drive up the price of natural gas.
Regulations and Environmental Matters
The Partnership must sell an aggregate annual average of approximately
80,000 lbs/hr from Unit 1 and Unit 2 combined for use as process steam by
General Electric and must satisfy other operating and ownership criteria in
order to comply with the requirements for a Qualifying Facility under PURPA. If
the Facility were to fail to meet such criteria, the Partnership may become
subject to regulation as a subsidiary of a holding company, a public utility
company or an electric utility company under PUHCA, the Federal Power Act (the
"FPA") and state utility laws. If the Facility loses its Qualifying Facility
status, its Power Purchase Agreements will be subject to the jurisdiction of the
FERC under the FPA. The Partnership may nevertheless be exempt from regulation
under PUHCA if it maintains "exempt wholesale generator" status. In 1994, the
Partnership filed with the FERC an Application for Determination of Exempt
Wholesale Generator Status, which was granted by the FERC.
15
In addition to being a Qualifying Facility, Unit 1, prior to the
commencement of operations by Unit 2, was a New York State co-generation
facility under the New York Public Service Law and consequently exempt from most
regulation otherwise applicable under that law to Unit 1's steam and electric
operations. The Partnership has obtained from the NYPSC a declaratory order that
the Facility will not be subject to regulation as an electric corporation, steam
corporation or gas corporation under the New York Public Service Law, except to
the extent necessary to implement safety and environmental regulation. Under
certain circumstances, and subject to the conditions set forth in the Indenture,
the Partnership may become subject to regulation under the New York Public
Service Law as an electric corporation, steam corporation or gas corporation.
For example, if the Partnership were to engage in sales of electricity to
General Electric at the GE Plant, the Partnership could be deemed an electric
corporation.
While the NYPSC has specifically authorized Unit 1 and Unit 2 to be
thermally integrated, the NYPSC has stated that Unit 1 and Unit 2 may not be
electrically interconnected.
All regulatory approvals currently required to operate the combined
Facility have been obtained. The Partnership is subject to federal, state, and
local laws and regulations pertaining to air and water quality, and other
environmental matters. In response to regulatory change, and in the course of
normal business, the Partnership files requisite documents and applies for a
variety of permits, modifications, renewals and regulatory extensions. It is not
possible to ascertain with certainty when or if the various required
governmental approvals and actions which are petitioned will be accomplished,
whether modifications of the Facility will be required or, generally, what
effect existing or future statutory action may have upon Partnership operations.
The 1990 amendments to the Federal Clean Air Act (the "1990 Clean Air
Amendments") require a large number of rulemaking and other actions by the
United States Environmental Protection Agency (the "EPA" or the "Agency") and
the New York State Department of Environmental Conservation (the "DEC"). The DEC
has adopted regulations for New York State's (the "State") operating permit
program consistent with the requirements of Title V of the 1990 Clean Air Act
Amendments and has received interim final approval of the State's program from
the EPA. Pursuant to the State's program the Facility is required to obtain a
new operating permit, an application for which was submitted to the DEC prior to
June 9, 1997. Except as set forth herein below, no material proceedings have
been commenced or, to the knowledge of the Partnership, are contemplated by any
federal, state or local agency against the Partnership, nor is the Partnership a
defendant in any litigation with respect to any matter relating to the
protection of the environment.
In December 1995, the Partnership received a letter from the EPA requesting
revision of periodic air emission reporting to the Agency. The Partnership
tendered an interim response to the inquiry in January 1996. Although mutual
consensus regarding a reporting format is anticipated, the Partnership cannot
determine what, if any, actions could potentially
16
be taken by the EPA. As of the date of this report, the Partnership has not
received any further correspondence from the EPA regarding this matter.
In January 1997, the Partnership received a letter from the EPA indicating
that the Agency completed its statutorily required review of the Facility's
Facility Response Plan ("FRP"), as submitted to the EPA in September 1994
pursuant to the codified requirements of the Oil Pollution Control Act of 1990.
Accompanying this letter the Partnership received a listing of requested
administrative revisions to the FRP. In February 1997 the Facility underwent an
FRP field inspection and in March 1997, the Partnership received a letter from
the EPA indication that there were no "site specific violations" identified
during the field inspection. In January 1998, the Partnership received a letter
from the EPA requesting additional administrative revisions to Revision 2 of the
Facility FRP submitted to the EPA during May 1997. On April 3, 1998, the EPA
approved Revision 2 of the Facility FRP.
Employees
The Partnership has no employees. The Project Management Firm provides
overall management and administration services to the Partnership pursuant to a
Project Administrative Services Agreement. The Project Management Firm provides
ten site employees and support personnel in its Boston, Massachusetts and
Bethesda, Maryland offices, who manage Unit 1 and Unit 2 on a combined basis.
General Electric through its O&M Services component (the "Operator")
provides operation and maintenance services for the Facility pursuant to an
Amended and Restated Operation and Maintenance Agreement between the Partnership
and General Electric (the "O&M Agreement"). The Operator has substantial
experience in operating and maintaining generating facilities using combustion
turbine and combined cycle technology and provides 32 employees to operate the
Facility.
ITEM 2. PROPERTIES
The Facility is located in the Town of Bethlehem, County of Albany, New
York, on approximately 15.7 acres of land (the "Facility Site") which is leased
by the Partnership from General Electric. In addition, the Partnership laterally
owns an approximately 2.1 mile pipeline which is used for the transportation of
natural gas from a point of interconnection with Tennessee's pipeline facilities
to the Facility Site. General Electric has granted certain permanent easements
for the location of certain of the Unit 1 and Unit 2 interconnection facilities
and other structures.
The Partnership has leased the Facility to the Town of Bethlehem Industrial
Development Agency (the "IDA") pursuant to a facility lease agreement. The IDA
has leased the Facility back to the Partnership pursuant to a sublease
agreement. The IDA's participation
17
exempts the Partnership from certain mortgage recording taxes, certain state and
local real property taxes and certain sales and use taxes within New York State.
ITEM 3. LEGAL PROCEEDINGS
The Partnership is party to the legal proceedings described below.
Gas Transportation Proceedings
As part of the ordinary course of business, the Partnership routinely files
complaints and intervenes in rate proceedings filed with the FERC by its gas
transporters, as well as related proceedings. During the first quarter of 1997,
the FERC approved a settlement between the Partnership and Tennessee. The
settlement was beneficial to the Partnership in that the Partnership received
refunds for reductions in rates and established a mechanism whereby future rates
would step down.
A rate filing with the FERC made by Iroquois is currently pending. Iroquois
is seeking rate adjustments and authority to collect additional costs for gas
transportation services. During July 1998, FERC issued an initial decision,
which would result in an approximate 25% reduction in rates charge by Iroquois.
The initial decision is under appeal by Iroquois and the Partnership is
anticipating a final decision by the FERC in the near future. In a rate
proceeding involving Tennessee, the Partnership along with other incremental
shippers appealed FERC's decision to reject roll-in of the incremental
facilities into the general system. A successful decision would have
substantially reduced the rates for incremental shippers. The circuit court has
recently issued a decision upholding FERC's decision to reject roll-in. During
1999, FERC will be focusing on Notice of Proposed Rulemaking and Notice of
Inquiry Initiatives. Under these Initiatives FERC will be reviewing many issues
affecting the regulation of interstate natural gas pipelines, including such
matters as short term capacity release mechanisms, negotiated rates, rate design
and a general standardization of business practices.
Curtailment
In August 1992, Niagara Mohawk filed a petition requesting the NYPSC to
authorize Niagara Mohawk to curtail purchases from, and avoid payment
obligations to, non-utility generators, including Qualifying Facilities such as
the Facility during certain periods. Niagara Mohawk claimed that such
curtailment would be consistent with PURPA, and the regulations promulgated
thereunder, which contemplates utilities' curtailing purchases from Qualifying
Facilities under certain circumstances. In October 1992, the NYPSC initiated a
proceeding to investigate whether conditions existed justifying the exercise of
the PURPA curtailment rights and, if so, to determine the procedures for
implementing PURPA curtailment rights. Con Edison also filed a petition in this
proceeding seeking to implement PURPA curtailment rights during certain periods.
An administrative law judge appointed by the NYPSC held hearings during the
spring of 1993, however, his opinion was never released. On August 30, 1996, the
18
NYPSC reopened the curtailment proceedings and directed an administrative law
judge to prepare a recommended decision under an abbreviated deadline. On March
18, 1998, the NYPSC announced that an order instituting a curtailment policy
would be forthcoming, however, a written order has not yet been issued. In
conjunction with the execution of the Amended and Restated Niagara Mohawk Power
Purchase Agreement on August 21, 1998, Niagara Mohawk waived any rights to
curtail purchases from the Partnership.
With respect to the Con Edison petition, the Partnership has taken the
position in this proceeding that it should not be subject to curtailment as a
result of this proceeding, even if the NYPSC grants Con Edison some measure of
generic curtailment rights. The Partnership's position is based in part on the
fact that Con Edison did not bargain for an express curtailment right in its
Power Purchase Agreement and the Partnership agreed to permit Con Edison to
direct the dispatch of Unit 2. Nevertheless, Con Edison has refused to expressly
waive its claimed curtailment rights against dispatchable facilities and has not
agreed to exempt the Facility from curtailment, notwithstanding the absence of
contractual language in the Power Purchase Agreement granting the utility this
right. If Con Edison was to receive NYPSC authorization to curtail power
purchases from Qualifying Facilities including dispatchable facilities, it may
seek to implement curtailment with respect to the Partnership by avoiding not
only energy payments but also capacity payments during periods in which the
Facility is curtailed. Such a reduction in energy payments and capacity payments
could materially and adversely affect the Partnership's net operating revenues.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
19
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
There is no established public market for Funding Corporation's common
stock. The 10 issued and outstanding shares of common stock of Funding
Corporation, $1.00 par value per share, are owned by the Partnership. All of the
common equity interests of the Partnership are held by the Partners and,
therefore, there is no established public market for the Partnership's common
equity interests.
ITEM 6. SELECTED FINANCIAL DATA
Unit 1 and Unit 2 began commercial operations on April 17, 1992 and
September 1, 1994, respectively. The selected financial data set forth below
should be read in conjunction with the financial statements, related notes and
other financial information included elsewhere herein.
Year Ended December 31,
-----------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
(in thousands)
Statement of Operations
Data:
Operating revenues $165,986 $171,583 $174,442 $155,778 $ 72,707
Cost of revenues 112,487 121,305 119,747 114,491 52,331
Other operating expenses 5,130 6,584 6,669 7,174 5,009
Operating income 48,369 43,694 48,026 34,113 15,367
Net interest expense 32,048 32,234 32,844 32,392 17,094
Write-off of deferred finance
charges and interest rate hedge --- --- --- --- 34,885
---------- ---------- ------------ ------------ -----------
Net income (loss) $ 16,321 $ 11,460 $ 15,182 $ 1,721 $(36,612)
========== ========== ============ ============ ===========
December 31,
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
(in thousands)
Balance Sheet Data:
Plant and equipment (net) $308,999 $321,537 $334,229 $346,285 $354,440
Total assets 374,383 385,874 401,454 416,080 441,555
Long-term bonds 381,133 385,955 389,253 391,420 392,000
Partners' capital (46,810) (32,282) (18,810) 1,530 20,821
20
Supplementary Financial Information
The following is a summary of the quarterly results of operations for the
years ended December 31, 1996, December 31, 1997 and December 31, 1998.
Three Months Ended (unaudited)
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
(in thousands)
Year Ended
December 31, 1996
Operating revenues $ 46,405 $ 42,109 $ 41,139 $ 44,789
Gross Profit 16,572 12,276 11,569 14,278
Net income 6,275 2,491 1,716 4,700
Year Ended
December 31, 1997
Operating revenues $ 43,925 $ 40,850 $ 42,386 $ 44,422
Gross Profit 12,634 11,726 12,883 13,035
Net income 2,844 1,986 2,968 3,662
Year Ended
December 31, 1998
Operating revenues $ 41,409 $ 41,117 $ 43,421 $ 40,039
Gross Profit 13,301 12,347 15,986 11,865
Net income 3,722 2,792 7,430 2,377
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Overview
The Partnership owns a natural gas-fired, combined-cycle cogeneration
facility consisting of two units, with revenues derived primarily from sales of
electricity and, to a lesser extent, from sales of steam and natural gas. Unit 1
and Unit 2 began commercial operations on April 17, 1992 and September 1, 1994,
respectively. The Partnership earned net income of approximately $16.3 million
in 1998 and made cash distributions to the partners of approximately $30.8
million.
21
Results of Operations
Year Ended December 31, 1998 Compared to the Year Ended December 31, 1997
The Partnership earned net income of approximately $16.3 million for the
year ended December 31, 1998 as compared to net income of approximately $11.5
million for the prior year. The increase in net income is primarily due to an
increase in delivered energy to electric customers and lower fuel costs and
other operating expenses.
Total revenues for the year ended December 31, 1998 were approximately
$166.0 million as compared to approximately $171.6 million for the prior year.
Electric Revenues (dollars and kWh's in millions):
For the Year Ended
December 31, 1998 December 31, 1997
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ----- -------- --------
Unit 1 35.8 472.0 67.62% 74.60% 33.1 403.9 57.23% 62.61%
Unit 2 123.0 2,040.6 87.89% 91.74% 124.4 1,886.6 81.18% 89.89%
The "capacity factor" of Unit 1 and Unit 2 is the amount of energy produced
by each Unit in a given time period expressed as a percentage of the total
contract capability amount of potential energy production in that time period.
The "dispatch factor" of Unit 1 and Unit 2 is the number of hours scheduled
for electric delivery (regardless of output level) in a given time period
expressed as a percentage of the total number of hours in that time period.
Revenues from Unit 1 increased approximately $2.7 million for the year
ended December 31, 1998 as compared to the prior year. During the year ended
December 31, 1998 revenues from Niagara Mohawk and PG&E Energy Trading were
approximately $34.0 million and $1.8 million, respectively. During the year
ended December 31, 1997 all revenues from Unit 1 were from Niagara Mohawk. The
increase in revenues from Unit 1 for the year ended December 31, 1998 was
primarily due to an increase in delivered energy as evidenced by the increase in
capacity factors from 57.23% to 67.62%, and improved contract pricing resulting
from the execution of the Amended and Restated Niagara Mohawk Power Purchase
Agreement on August 31, 1998 with terms and conditions retroactive to July 1,
1998. During the eight months ended August 31, 1998, with the exception of March
and April, Niagara Mohawk dispatched Unit 1 on-line. 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 was sold under special dispatch arrangements which called
for the pricing of delivered energy at variable rates which were 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
relevant periods. Effective August 31, 1998, in conjunction with the execution
of the
22
Amended and Restated Niagara Mohawk Power Purchase Agreement, Niagara Mohawk no
longer has the right to direct the dispatch of Unit 1. See Part I Item 1.
Business The Facility and Certain Project Contracts Niagara Mohawk for a
detailed discussion of the Amended and Restated Niagara Mohawk Power Purchase
Agreement. During the six months ended December 31, 1998, with the exception of
October, the Partnership received Monthly Contract Payments and delivered energy
up to the monthly contract quantity to Niagara Mohawk. During the month of
October 1998, Niagara Mohawk was not required to make a Monthly Contract Payment
and the Partnership sold all of the generated energy from Unit 1 to PG&E Energy
Trading. During the months of July, August and September 1998 the Partnership
sold all of the Excess Energy generated from Unit 1 to Niagara Mohawk. During
the months of November and December 1998 the Partnership sold all of the Excess
Energy generated from Unit 1 to PG&E Energy Trading. Energy delivered to PG&E
Energy Trading was sold at negotiated market prices.
Deferred revenues of approximately $0.3 million are also included in
revenues from Niagara Mohawk during the year ended December 31, 1998. The
deferred revenues resulted from the consummation of the transactions pursuant to
the MRA. The $2.2 million payment made by the Partnership to Niagara Mohawk and
the $10.3 million of payments received by the Partnership from Niagara Mohawk
(representing net receipts to the Partnership of approximately $8.1 million)
were a condition to the Amended and Restated Niagara Mohawk Power Purchase
Agreement and are being deferred to be amortized over the ten-year term of the
Amended and Restated Power Purchase Agreement. In addition, approximately $1.2
million in restructuring costs will also be amortized over the ten-year term of
the Amended and Restated Niagara Mohawk Power Purchase Agreement. Deferred
Revenues of approximately $6.6 million appear on the Partnership's Consolidated
Balance Sheet at December 31, 1998.
During the year ended December 31, 1997, with the exception of April, May
and September, Niagara Mohawk dispatched Unit 1 on-line. Energy delivered during
the months of June, July and August was sold at full contract rates. Energy
delivered during January, February, March and December 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 pursuant to
special dispatch arrangements with Niagara Mohawk for the year ended December
31, 1998 were approximately $1.4 million as compared to approximately $6.2
million for the prior year.
Revenues from Unit 2 decreased approximately $1.4 million for the year
ended December 31, 1998 as compared to the prior year. During the year ended
December 31, 1998, revenues from Con Edison and PG&E Energy Trading were
approximately $122.8 million and $0.2 million as compared to approximately
$124.3 million and $0.1 million, respectively for the prior year. The decrease
in revenues from Unit 2 for the year ended December 31, 1998 was primarily due
to the decrease in the Con Edison contract price for delivered energy resulting
from lower index fuel prices. The decrease in the price of energy was partially
offset by the increase in delivered energy as evidenced by the increase in
capacity factors from 81.18% to 87.89%. Revenues from PG&E Energy Trading
resulted from sales of generated
23
capacity and energy in excess of contract amounts due under the Con Edison Power
Purchase Agreement.
Steam revenues for the year ended December 31, 1998 of approximately $0.3
million were reduced by a reserve of the same amount to reflect the annual
true-up so that General Electric would be charged a nominal amount which is the
annual equivalent of 160,000 lbs/hr. Steam revenues for the year ended December
31, 1997 of approximately $1.1 million were reduced by a reserve of
approximately $0.7 million to reflect the annual true-up. Delivered steam for
the year ended December 31, 1998 was approximately 1.4 billion pounds as
compared to approximately 1.5 billion pounds in the prior year.
Gas resale revenues for the year ended December 31, 1998 were approximately
$7.2 million on sales of approximately 3.2 million MMBtu's as compared to
approximately $13.6 million on sales of approximately 5.2 million MMBtu's for
the prior year. The $6.4 million decrease in gas resale revenues during the year
ended December 31, 1998 is primarily due to higher dispatch of Units 1 and 2 and
lower natural gas resale prices, which resulted in lower volumes of natural gas
becoming available for resale at lower prices. The decrease in natural gas
resale prices during the year ended December 31, 1998 generally resulted from
more moderate temperatures in the Northeast region as compared to colder
temperatures, which resulted in higher demand for natural gas, during the prior
year. The Partnership entered into gas resales during periods when Units 1 and 2
were not operating at full capacity.
Fuel costs for the year ended December 31, 1998 were approximately $82.4
million on purchases of approximately 28.2 million MMBtu's as compared to
approximately $90.5 million on purchases of approximately 28.2 million MMBtu's
for the prior year. The $8.1 million decrease in the cost of fuel was primarily
due to lower contract firm fuel rates which resulted from lower index fuel
prices and lower transportation demand costs. During the years ended December
31, 1998 and 1997, fuel costs were reduced by approximately $0.9 million and
$1.8 million, respectively as a result of the FERC approved settlement between
the Partnership and Tennessee. See Part I Item 3. Legal Proceedings Gas
Transportation Proceedings for a discussion of the settlement between the
Partnership and Tennessee. The Partnership has foreign currency swap agreements
to hedge against future exchange rate fluctuations under fuel transportation
agreements which are denominated in Canadian dollars. During the years ended
December 31, 1998 and 1997, fuel costs were increased by approximately $2.5
million and $1.5 million, respectively as a result of the currency swap
agreements.
Operating and maintenance expenses for the year ended December 31, 1998
were approximately $17.6 million as compared to approximately $18.1 million for
the prior year. The $0.5 million decrease in operating and maintenance expenses
was primarily due to lower utility and depreciation expenses.
Total other operating expenses, excluding amortization of deferred
financing charges, for the year ended December 31, 1998 were approximately $4.0
million as compared to approximately $5.4 million for the prior year. The $1.4
million decrease in other operating
24
expenses, excluding amortization of deferred financing charges was due to lower
affiliate administrative services and lower external legal and consulting
services. The decrease in other operating expenses, excluding amortization of
deferred financing charges was partially offset by a charge to write-off
capitalized start-up costs in accordance with Statement of Position 98-5. See
Note 2 to the Consolidated Financial Statements for a discussion of Statement of
Position 98-5.
Amortization of deferred financing charges of approximately $1.2 million
for the year ended December 31, 1998 was comparable to the prior year. Deferred
financing charges are amortized using the effective interest method.
Net interest expense for the year ended December 31, 1998 was approximately
$32.0 million as compared to approximately $32.2 million for the prior year. The
decrease in net interest expense is primarily due to lower bond interest expense
resulting from the lower principal balance outstanding.
Year Ended December 31, 1997 Compared to the Year Ended December 31, 1996
The Partnership earned net income of approximately $11.5 million for the
year ended December 31, 1997 as compared to net income of approximately $15.2
million for the prior year. The decrease in net income is primarily due to lower
gas resale revenues, which was primarily due to the higher dispatch and capacity
of Units 1 and 2.
Total revenues for the year ended December 31, 1997 were approximately
$171.6 million as compared to approximately $174.4 million for the prior year.
Electric Revenues (dollars and kWh's in millions):
For the Year Ended
December 31, 1997 December 31, 1996
------------------------------------- -------------------------------------
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ----- -------- --------
Unit 1 33.1 403.9 57.23% 62.61% 29.9 303.1 44.81% 54.50%
Unit 2 124.4 1,886.6 81.18% 89.89% 117.2 1,623.7 69.71% 87.61%
Revenues from Unit 1 increased approximately $3.2 million for the year
ended December 31, 1997 as compared to the prior year. During the years ended
December 31, 1997 and 1996 all of the revenues from Unit 1 were from Niagara
Mohawk. Revenues for the year ended December 31, 1997 were favorably impacted by
an increase in delivered energy to Niagara Mohawk, as evidenced by the increase
in the capacity factors from 44.81% to 57.23% which was partially offset by a
decrease in the Niagara Mohawk contract price for delivered energy. For the year
ended December 31, 1997, Niagara Mohawk dispatched Unit 1 on-line for the months
of January, February, March, June, July, August, October, November and December
at full contract rates except for the months of January, February, March and
December. Energy delivered in January, February, March and December was sold
under special dispatch arrangements which called for the pricing of the
delivered energy at variable
25
rates less than full contract rates. For the year ended December 31, 1996,
Niagara Mohawk dispatched Unit 1 on-line for all months except March primarily
at full contract rates. Revenues for energy delivered pursuant to special
dispatch arrangements with Niagara Mohawk for the year ended December 31, 1997
were approximately $6.2 million as compared to approximately $29.0 thousand for
the prior year.
Revenues from Unit 2 increased approximately $7.2 million for the year
ended December 31, 1997 as compared to the prior year. During the year ended
December 31, 1997, revenues from Con Edison and PG&E Energy Trading were
approximately $124.3 million and $0.1 million as compared to approximately
$117.1 million and $0.1 million, respectively for the prior year. The increase
in revenues from Unit 2 for the year ended December 31, 1997 was primarily due
to an increase in delivered energy as evidenced by the increase in capacity
factors from 69.71% to 81.18%.
Pursuant to the Steam Sales Agreement General Electric may implement
productivity or energy efficiency projects in its manufacturing processes,
including projects involving the production of steam within the GE Plant
commencing in 1996. General Electric implemented an energy efficiency project in
1997 that reduced the quantity of steam required by the GE Plant. Under the
energy efficiency project, General Electric anticipates managing its annual
average steam demand at 160,000 lbs/hr. Steam revenues for the year ended
December 31, 1997 of approximately $1.1 million were reduced by a reserve of
approximately $0.7 million to reflect the annual true-up so that General
Electric would be charged a nominal amount which is the annual equivalent of
160,000 lbs/hr. Steam revenues for the year ended December 31, 1996 of
approximately $2.9 million were reduced by a reserve of approximately $0.2
million to reflect the annual true-up. Delivered steam for the year ended
December 31, 1997 was approximately 1.5 billion pounds as compared to
approximately 1.9 billion pounds in the prior year. The decrease in steam
revenues is due to lower steam demand as a result of the energy efficiency
project implemented by General Electric.
Gas resale revenues for the year ended December 31, 1997 were approximately
$13.6 million on sales of approximately 5.2 million MMBtu's as compared to
approximately $24.6 million on sales of approximately 7.9 million MMBtu's for
the prior year. The $11.0 million decrease in gas resale revenues during the
year ended December 31, 1997 as compared to the prior year is primarily due to
higher dispatch of Units 1 and 2, which resulted in lower volumes of natural gas
becoming available for resale. The decrease in average natural gas resale prices
generally resulted from the timing of when natural gas resales occurred during
the year ended December 31, 1997 as compared to the prior year. Dispatch of the
Units during the year ended December 31, 1996 allowed for gas resales to occur
during peak natural gas resale price periods as compared to the current year.
The Partnership entered into gas resales during periods when Units 1 and 2 were
not operating at full capacity.
Fuel costs for the year ended December 31, 1997 were approximately $90.5
million on purchases of approximately 28.2 million MMBtu's as compared to
approximately $89.2 million on purchases of approximately 28.5 million MMBtu's
for the prior year. The $1.3 million increase in the cost of fuel primarily
resulted from higher contract firm fuel rates due
26
to higher index fuel prices and rate increases under the firm transportation
contracts. During the year ended December 31, 1997, fuel costs were reduced by
approximately $1.8 million as a result of the FERC approved settlement between
the Partnership and Tennessee. See Part I Item 3. Legal Proceedings Gas
Transportation Proceedings for a discussion of the settlement between the
Partnership and Tennessee. The 0.3 million MMBtu decrease for the year ended
December 31, 1997 as compared to the prior year is primarily due to a reduction
in firm fuel purchases from suppliers. The Partnership has foreign currency swap
agreements to hedge against future exchange rate fluctuations under fuel
transportation agreements which are denominated in Canadian dollars. During the
years ended December 31, 1997 and 1996, fuel costs were increased by
approximately $1.5 million and $1.3 million, respectively as a result of the
currency swap agreements.
Operating and maintenance expenses for the year ended December 31, 1997
were approximately $18.1 million as compared to approximately $17.9 million for
the prior year. Operating and maintenance expenses for the year ended December
31, 1997 are comparable to the prior year.
Total other operating expenses, excluding amortization of deferred
financing charges, for the year ended December 31, 1997 were approximately $5.4
million as compared to approximately $5.5 million for the prior year. Other
operating expenses, excluding amortization of deferred financing charges for the
year ended December 31, 1997 are comparable to the prior year.
Amortization of deferred financing charges of $1.2 million for the year
ended December 31, 1997 was comparable to the prior year. Deferred financing
charges are amortized using the effective interest method.
Net interest expense for the year ended December 31, 1997 was approximately
$32.2 million as compared to approximately $32.8 million for the prior year. The
decrease in net interest expense is primarily due to higher interest income and
lower bond interest expense resulting from the lower principal balance
outstanding.
Liquidity and Capital Resources
Net cash provided by operating activities for the year ended December 31,
1998 was approximately $37.5 million as compared to approximately $26.6 million
for the prior year. The increase in net cash provided by operating activities is
primarily due to the increase in net income and the net activity of
approximately $6.9 million resulting from the consummation of the transactions
relating to the Amended and Restated Niagara Mohawk Power Purchase Agreement
pursuant to the MRA. See Part I Item 1. Business The Facility and Certain
Project Contracts Niagara Mohawk for a detailed discussion of the Amended and
Restated Niagara Mohawk Power Purchase Agreement.
27
Net cash used in investing activities for the year ended December 31, 1998
was approximately $177.0 thousand as compared to net cash provided by investing
activities of approximately $16.0 thousand for the prior year. Net cash flows
used in or provided by investing activities primarily represent additions or
adjustments to plant and equipment, respectively. During the year ended December
31, 1998, approximately $260.0 thousand of previously capitalized start-up costs
were written-off in accordance with Statement of Position 98-5. See Note 2 to
the Consolidated Financial Statements for a discussion of Statement of Position
98-5.
Net cash used in financing activities for the year ended December 31, 1998
was approximately $36.8 million as compared to approximately $27.9 million for
the prior year. The increase in net cash flows used in financing activities for
the year ended December 31, 1998 is primarily due to more cash becoming
available to distribute to Partners and deposit into Restricted Funds. Pursuant
to the Partnership's Depositary and Disbursement Agreement, administered by
Bankers Trust Company, as depositary agent, the Partnership is required to
maintain certain Restricted Funds. Net cash flows used in financing activities
for the years ended December 31, 1998 and 1997 primarily represent distributions
of monies to Partners, net deposits of monies into the Major Maintenance Reserve
Fund and Debt Service Reserve Fund and payments of principal on long-term debt.
The debt service coverage ratio for 1998 calculated pursuant to the
Indenture was 1.83:1.
Credit Agreement
The Partnership has available for its use a $10.4 million Credit Agreement
("Credit Agreement"), which is to be used by the Partnership for required
letters of credit related to various project contracts and for working capital
purposes. The maximum amount available under the Credit Agreement for working
capital purposes is $5.0 million. At December 31, 1998, no draws had been made
against the outstanding letters of credit and no working capital loans were
outstanding under the Credit Agreement. The Credit Agreement expires on August
1, 2001.
Funds
In connection with the sale of the Bonds, the Partnership entered into the
Deposit and Disbursement Agreement (the "D&D Agreement") which requires the
establishment and maintenance of certain segregated funds (the "Funds") and is
administered by Bankers Trust Company, as depositary agent. Pursuant to the D&D
Agreement a number of Funds were established. Some of the Funds have been
terminated since the purposes of such Funds were achieved and are no longer
required, some Funds are currently active and some Funds activate at future
dates upon the occurrence of certain events. The significant Funds that are
currently active are the Project Revenue Fund, Major Maintenance Reserve Fund,
Interest Fund, Principal Fund, Debt Service Reserve Fund and two sub-funds of
the Partnership Distribution Fund.
28
All Partnership cash receipts and operating cost disbursements flow through
the Project Revenue Fund. As determined on the 20th of each month, any monies
remaining in the Project Revenue Fund after the payment of operating costs are
used to fund the above named Funds based upon the Fund hierarchy and in the
amounts (each, a "Fund Requirement") established pursuant to the D&D Agreement.
The Major Maintenance Reserve Fund relates to certain anticipated annual
and periodic major maintenance to be performed on certain of the Facility's
machinery and equipment at future dates. The Fund Requirement is developed by
the Partnership and approved by an independent engineer for the Trustee and can
be adjusted on an annual basis, if needed. At December 31, 1998, the balance in
this Fund was approximately $5.6 million, which exceeded the current Fund
Requirement of $4.4 million.
The Interest and Principal Funds relate primarily to the current debt
service on the outstanding Bonds. The applicable Fund Requirement is the amount
due and payable on the next semi-annual payment date. On December 26, 1998, the
monies available in the Interest and Principal Funds were used to make the
semi-annual interest and principal payments. Therefore, the balance in the
Interest and Principal Funds at December 31, 1998 were $0. The June 26, 1999
Interest and Principal Fund Requirements will be approximately $17.1 million and
approximately $2.0 million, respectively.
The Fund Requirement for the Debt Service Reserve Fund is an amount equal
to the maximum amount of debt service due in respect of all the Bonds
outstanding for any six-month period during the succeeding three-year period. At
December 31, 1998, the balance in this Fund was approximately $22.6 million. The
June 26, 1999 Fund Requirement will remain at approximately $22.6 million.
The Partnership Distribution Fund is at the end of the Fund hierarchy and
cash distributions to the Partners from these sub-funds can only be made upon
the achievement of specific criteria established pursuant to the financing
documents, including the D&D Agreement. This Fund does not have a Fund
Requirement.
Refinancing
At March 31, 1994, the Partnership had an existing credit facility which
included a term loan with an outstanding balance of $96.3 million and a
construction loan with an outstanding balance of $232.4 million. On May 9, 1994
(the "Closing Date") all amounts outstanding under the then existing credit
facility were refinanced with the Old Bonds. The Partnership determined that a
refinancing of the existing credit facility would benefit the long term
operating results of the Partnership, despite the cost to terminate the interest
rate swap agreements related to the then existing debt. This decision was a
result of management's review of then prevailing market interest rates and the
term of the then prevailing credit facility.
29
On the Closing Date, the proceeds from the sale of the $392 million in Old
Bonds together with approximately $53.8 million available under an equity bridge
loan facility were used to refinance all amounts outstanding under the then
existing credit facility, to pay approximately $17.4 million in interest rate
swap breakage costs associated with the termination of the Partnership's
interest rate hedging agreements pertaining to the then existing debt and
approximately $17.4 million in transaction costs related to the offering of the
Old Bonds and to establish certain reserve Funds under the D&D Agreement. The
Partnership also received approximately $5.1 million in capital contributions
from certain Partners on the Closing Date and approximately $53.8 million in
additional capital contributions from certain Partners following commercial
operations of Unit 2, which was used in part to repay the Partnership's
obligations under the equity bridge loan facility.
In November 1994, the Funding Corporation and Partnership offered to
exchange like amounts of the New Bonds for Old Bonds. On December 12, 1994, the
exchange of all the Old Bonds for the New Bonds was completed.
Year Ended December 31, 1999
During 1999, the Partnership anticipates Con Edison to dispatch the Unit 2
at levels consistent with the prior year. In order to achieve dispatch levels
similar to those of the prior year, or exceed them, the Partnership may enter
into special dispatch arrangements which will ultimately enhance the operations,
revenues and cash flows of the Partnership. Additionally, the Amended and
Restated Niagara Mohawk Power Purchase Agreement transfers dispatch
decision-making authority from Niagara Mohawk to the Partnership. In effect,
Unit 1 will operate on a "merchant-like" basis, whereby the Partnership will
have the ability and flexibility to dispatch Unit 1 based on, then current,
market conditions.
As of March 1999, natural gas resale prices for 1999 have been below the
prior year's prices and the Partnership expects, on the average, such prices to
remain below 1998 levels for the balance of 1999.
Future operating results and cash flows from operations are also dependent
on, among other things, the performance of equipment and processes as expected,
levels of dispatch, the receipt of certain capacity and other fixed payments,
electricity prices, natural gas resale prices, fuel deliveries and prices as
contracted. 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.
30
Year 2000
The Year 2000 issue exists because many computer programs use only two
digits to refer to a year, and was developed without considering the impact of
the upcoming change in the century. If the Partnership's computer systems fail
or function incorrectly due to not being made Year 2000 ready, they could
directly and adversely affect the Partnership's ability to generate or deliver
products and services or could otherwise affect safety, revenues or reliability
for such a period of time as to lead to unrecoverable consequences.
The Partnership's plan to address the Year 2000 issues focuses on
mission-critical systems whose components are categorized as in-house software,
vendor software, embedded systems and computer hardware. The four phases of the
plan to address these systems are inventory and assessment, remediation,
testing, and certification. Certification occurs when mission-critical systems
are formally determined to be Year 2000 ready.
The Partnership's Year 2000 project is proceeding generally on schedule.
The Partnership has determined that its only mission-critical software is vendor
software. As to mission-critical vendor software, Year 2000 ready upgrades are
being obtained from the vendors, tested as appropriate and certified once all
necessary steps are completed. The Partnership expects to finish this process
for all mission-critical vendor software in the second quarter of 1999.
The Partnership is testing remediated software and embedded systems both
for ability to handle Year 2000 dates, including appropriate leap year
calculations, and to assure that code repair has not affected the base
functionality of the code. Software and embedded systems are tested individually
and where necessary will be tested in an integrated manner with other systems,
with dates and data advanced and aged to simulate Year 2000 operations. Testing,
by its nature, however, cannot comprehensively address all future combinations
of dates and events. Some uncertainty will remain after testing as to the
ability of code to process future dates, as well as the ability of remediated
systems to work in an integrated fashion with other systems.
In addition to internal systems, the Partnership depends upon external
parties, including customers, suppliers, business partners, gas and electric
system operators, government agencies, and financial institutions to support the
functioning of its business. To the extent that any of these parties are
considered mission-critical to the Partnership's business and experience Year
2000 problems in their systems, the Partnership's mission-critical business
functions may be adversely affected. To deal with this vulnerability, the
Partnership has another phased approach. The primary phases for dealing with
external parties are: (1) inventory, (2) action planning, (3) risk assessment,
and (4) contingency planning.
The Partnership has completed its inventory and action planning phases for
mission-critical external parties. The Partnership expects to complete the risk
assessment and contingency planning phases in the second quarter of 1999.
31
Although the Partnership expects its efforts and those of its external
parties to be largely successful, the Partnership recognizes that with the
complex interaction of today's computing and communication systems, it cannot be
certain the Partnership will be completely successful. Therefore, contingency
plans for Year 2000 readiness are being developed and tested throughout 1999 to
address its external dependencies as well as any significant schedule delays of
mission-critical system work, should they occur. These plans will take into
account possible interruptions of power, computing, financial, and
communications infrastructures. Due to the speculative nature of contingency
planning, however, it is uncertain whether these plans will be sufficient to
remove the risk of material impacts on the Partnerships operations resulting
from Year 2000 problems.
Through December 1998, the Partnership spent approximately $126,000 to
assess and remediate Year 2000 problems. The Partnership's estimate of future
costs to address mission-critical Year 2000 issues is approximately $315,000.
About $100,000 of these remaining Year 2000 costs will be capitalized because
they relate to the purchase and installation of systems and equipment for
general business purposes, and the remaining $215,000 will be expensed.
Based on the Partnership's current schedule for the completion of Year 2000
tasks, the Partnership expects to secure Year 2000 readiness of its
mission-critical systems on or before the end of the third quarter of 1999.
However, as the Partnership's current schedule is partially dependent on the
efforts of third parties, their delays may cause the Partnership's schedule to
change.
If the Partnership, or third parties with whom the Partnership has
significant business relationships, fail to achieve Year 2000 readiness of
mission-critical systems, there could be a material adverse impact on the
Partnership's financial position, results of operations, and cash flows.
Cautionary Statement Regarding Forward-Looking Statements
Certain statements included herein are forward-looking statements
concerning the Partnership's operations, economic performance and financial
condition. Such statements are subject to various risks and uncertainties.
Actual results could differ materially from those currently anticipated due to a
number of factors, including general business and economic conditions, the
performance of equipment and processes as expected, levels of dispatch, the
receipt of certain capacity and other fixed payments, electricity prices,
natural gas resale prices, fuel deliveries and prices as contracted and issues
related to year 2000 compliance.
32
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Partnership is exposed to market risk from changes in interest rates
and foreign currency exchange rates, which could affect its future results of
operations and financial condition. The Partnership manages its exposure to
these risks through its regular operating and financing activities. The
Partnership does not enter into derivative financial instruments for trading
purposes.
Interest Rates
The Partnership's cash and restricted cash are sensitive to changes in
interest rates. Interest rate changes would result in a change in interest
income due to the difference between the current interest rates on cash and
restricted cash and the variable rate that these financial instruments may
adjust to in the future. A 10% decrease in year-end 1998 interest rates would
result in a negative impact of approximately $0.2 million on the Partnership's
net income.
The Partnership's long-term bonds have fixed interest rates. Changes in the
current market rates for the bonds would not result in a change in interest
expense due to the fixed coupon rate of the bonds. See Notes 4 and 5 to the
Consolidated Financial Statements.
Foreign Currency Exchange Rates
The Partnership's currency swap agreements hedge against future exchange
rate fluctuations which could result in additional costs incurred under fuel
transportation agreements which are denominated in a foreign currency. In the
event a counterparty fails to meet the terms of the agreements, the
Partnership's exposure is limited to the currency exchange rate differential.
During the year ended December 31, 1998 the exchange rate differential would
have a negative impact of approximately $2.5 million on the Partnership's net
income. See Notes 4 and 5 to the Consolidated Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
-------------------------------------------
The financial statements and supplementary data required by this item are
presented under Item 14 and are incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
-----------------------------------------------------------
None.
33
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE FUNDING CORPORATION
AND THE MANAGING GENERAL PARTNER
-----------------------------------------------------------
The Managing General Partner is authorized to manage the day to day
business and affairs of the Partnership and to take actions which bind the
Partnership, subject to certain limitations set forth in the Partnership
Agreement. The Managing General Partner has a Board of Directors consisting of
two persons elected by its sole stockholder, JMC Selkirk Holdings, Inc.
("Holdings"), a direct subsidiary of Beale. Pursuant to a board representation
agreement with GPUI, Holdings may elect at least four members, and GPUI has the
right, at its option, to designate a fifth member of the Board of Directors of
the Managing General Partner.
The following tables set forth the names, ages and positions of the
directors and executive officers of the Funding Corporation and the Managing
General Partner and their positions with the Funding Corporation and the
Managing General Partner. Directors are elected annually and each elected
director holds office until a successor is elected. The executive officers of
each of the Funding Corporation and the Managing General Partner are chosen from
time to time by vote of its Board of Directors.
Selkirk Cogen Funding Corporation:
Name Age Position
---- --- --------
P. Chrisman Iribe...... 47 President and Director
Stephen A. Herman...... 55 Director
John R. Cooper......... 51 Senior Vice President and Chief
Financial Officer
Douglas F. Egan........ 41 Senior Vice President
David N. Bassett....... 51 Treasurer
Managing General Partner:
------------------------
Name Age Position
---- --- --------
P. Chrisman Iribe....... 47 President and Director
Stephen A. Herman....... 55 Director
John R. Cooper.......... 51 Senior Vice President and Chief
Financial Officer
Douglas F. Egan......... 41 Senior Vice President
David N. Bassett........ 51 Treasurer
P. Chrisman Iribe is President and Chief Operating Officer of U.S.
Generating, an affiliate of the Partnership, and has been with U.S. Generating
since it was formed in 1989. Prior to joining U.S. Generating, Mr. Iribe was
senior vice president for planning, state
34
relations and public affairs with ANR Pipeline Company, a natural gas pipeline
company and a subsidiary of the Coastal Corporation. Mr. Iribe has been a
Director of the Funding Corporation since 1996 and a Director of the Managing
General Partner since 1995.
Stephen A. Herman is Senior Vice President and General Counsel of U.S.
Generating, an affiliate of the Partnership, and has been with U.S. Generating
since August 1990. . Prior to joining U.S. Generating, he was a partner for 15
years with the Washington, D.C. law firm of Kirkland and Ellis. Mr. Herman has
been a Director of the Funding Corporation and the Managing General Partner
since 1998.
John R. Cooper is Senior Vice President and Chief Operating Officer of U.S.
Generating, an affiliate of the Partnership, and has been with U.S. Generating,
since it was formed in 1989. Prior to joining U.S. Generating, he spent 3 years
as a Chief Financial Officer with a European oil, shipping and banking group.
Prior to 1986, Mr. Cooper spent 7 years with Bechtel Financing Services, Inc.,
where his last position was Vice President and Manager.
Douglas F. Egan is Senior Vice President of U.S. Generating, an affiliate
of the Partnership, and has been with U.S. Generating since Beale's acquisition
of J. Makowski Company in 1995 where he was vice president of the electric
projects group. Prior to 1991 he was general counsel for Intercontinental Energy
Corporation, a developer and owner/operator of cogeneration facilities. Prior to
1987 he was an associate with the law firm of Murtha Cullina Richter & Pinney.
David N. Bassett is Controller and Treasurer of U.S. Generating, an
affiliate of the Partnership, and has been with U.S. Generating since it was
formed in 1989. Mr. Bassett oversees all accounting and auditing activities,
treasury functions and insurance for the projects in which U.S. Generating or
certain of its affiliates play a role. Prior to joining U.S. Generating, he
worked for Bechtel Enterprises, Inc. and Bechtel Group for over 15 years.
General Partners' Representatives of the Management Committee
The Management Committee established under the Partnership Agreement
consists of one representative of each of the General Partners. Each General
Partner has a voting representative on the Management Committee, which, subject
to certain limited exceptions, acts by unanimity. GPUI is entitled to name a
designee to participate on a non-voting basis in meetings of the Management
Committee.
ITEM 11. EXECUTIVE AND BOARD COMPENSATION AND BENEFITS
No cash compensation or non-cash compensation was paid in any prior year or
during the year ended December 31, 1998 to any of the officers, directors and
representatives referred to under Item 10 above for their services to the
Funding Corporation, the Managing General
35
Partner or the Partnership. Overall management and administrative services for
the Facility are being performed by the Project Management Firm at agreed-upon
billing rates which are adjusted quadrennially, if necessary, pursuant to the
Administrative Services Agreement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The Partnership is a limited partnership wholly owned by its Partners. The
following information is given with respect to the Partners of the Partnership:
Nature
Name and Address of Beneficial Percentage
Title of Class of Beneficial Owner Ownership (1) Interest (2)
- -------------- ------------------- ------------- ------------
Partnership Interest JMC Selkirk, Inc. (3) Managing General (i) 2.0417%
One Bowdoin Square Partner (ii) 22.4000%
Boston, Massachusetts 02114 Limited Partner (iii) 18.1440%
Partnership Interest PentaGen Investors, L.P.* (3)(4) Limited Partner (i) 5.2502%
One Bowdoin Square (ii) 57.6000%
Boston, Massachusetts 02114 (iii) 46.6560%
Partnership Interest Cogen Technologies General Partner (i) 1.0000%
Selkirk GP, Inc. (iii) .2211%
1700 Louisiana Street
Houston, Texas 77002 (5)
Partnership Interest Cogen Technologies Limited Partner (i) 78.1557%
Selkirk LP, Inc. (iii) 17.2789%
1700 Louisiana Street
Houston, Texas 77002 (5)
Partnership interest EI Selkirk, Inc. (6) Limited Partner (i) 13.5523%
One Upper Pond Road (ii) 20.0000%
Parsippany, New Jersey 07054 (iii) 17.7000%
*Formerly known as JMCS I Investors, L.P.
(1) None of the persons listed has the right to acquire beneficial ownership of
securities as specified in Rule 13d-3(d) under the Exchange Act.
(2) Percentages indicate the interest of (i) each of the Partners in certain
priority distributions of available cash of the Partnership, up to fixed
semi-annual amounts (the "Level I Distributions"), (ii) JMC Selkirk,
Investors and EI Selkirk in 99% of distributions of the remaining available
cash of the Partnership; and (iii) each of the Partners in the residual
tier of interests in cash distributions after the initial 18-year
36
period following the completion of Unit 2 (or, if later, the date when all
Level I Distributions have been paid).
(3) Beale (formerly known as J. Makowski Company) is the indirect beneficial
owner of JMC Selkirk and a 50% indirect beneficial owner of Investors. The
capital stock of Beale is held by USGen Power (89.1%) and Cogentrix
(10.9%).
(4) 50% of the interests in Investors are beneficially owned by Tomen
Corporation, a Japanese trading company.
(5) Cogen Technologies GP is beneficially owned by Robert C. McNair (88.3%) and
members of his family (11.7%). As of February 4, 1999, Cogen Technologies
LP is beneficially owned by 100% by Robert C. McNair. Mr. McNair has voting
control of each of Cogen Technologies GP and Cogen Technologies LP.
(6) EI Selkirk is a wholly owned subsidiary of GPUI.
Except as specifically provided or required by law and in certain other
limited circumstances provided in the Partnership Agreement, Limited Partners
may not participate in the management or control of the Partnership. The
Managing General Partner is an affiliate of Investors, which is a Limited
Partner, and JMCS I Management, the Project Management Firm. Cogen Technologies
GP and Cogen Technologies, L.P. are also affiliated.
All of the issued and outstanding capital stock of the Funding Corporation
is owned by the Partnership.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
JMCS I Management, an indirect, wholly-owned subsidiary of PG&E Generating,
provides management and administrative services for the Facility under the
Administrative Services Agreement. All of the directors and officers of the
Managing General Partner and the Funding Corporation listed in Item 10 of this
Report are also directors or officers, as the case may be, of JMCS I Management.
See Note 7 to the Consolidated Financial Statements, appearing elsewhere in this
report, for a discussion of the Partnership's related party transactions.
37
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K
(a) 1. Financial Statements
The following financial statements are filed as part of this Report:
Report of Independent Public Accountants .................... F-1
Consolidated Balance Sheets as of December 31, 1998 and 1997.. F-2
Consolidated Statements of Operations for the years ended
December 31, 1998, 1997 and 1996.............................. F-3
Consolidated Statements of Partners' Capital for the years ended
December 31, 1998, 1997 and 1996.............................. F-4
Consolidated Statements of Cash Flows for the years ended
December 31, 1998, 1997 and 1996.............................. F-5
Notes to Consolidated Financial Statements.................... F-6
2. Financial Statement Schedule
The following financial statement schedule is filed as part of this
Report:
Schedule II Valuation and Qualifying Accounts............. S-1
All other schedules have been omitted because the information is not
applicable.
3. Exhibits
The exhibits listed on the accompanying Index to Exhibits are filed as
part of this Report.
(b) Reports on Form 8-K
On March 9, 1999, the Registrant filed a report on Form 8-K disclosing
a change in its independent accounting firm.
38
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners of
Selkirk Cogen Partners, L.P.:
We have audited the accompanying consolidated balance sheets of Selkirk Cogen
Partners, L.P. (a Delaware limited partnership) and its subsidiary as of
December 31, 1998 and 1997, and the related consolidated statements of
operations, partners' capital and cash flows for each of the three years ended
December 31, 1998. These consolidated financial statements are the
responsibility of the Partnership's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, based on our audits, the financial statements referred to above
present fairly, in all material respects, the financial position of Selkirk
Cogen Partners, L.P. and its subsidiary as of December 31, 1998 and 1997, and
the results of their operations and their cash flows for each of the three years
ended December 31, 1998, in conformity with generally accepted accounting
principles.
Our audits were made for the purpose of forming an opinion on the consolidated
financial statements taken as a whole. The schedule listed in Item 14 is the
responsibility of the Partnership's management and is presented for purposes of
complying with the Securities and Exchange Commissions rules and is not part of
the basic consolidated financial statements. This schedule has been subjected to
the auditing procedures applied in the audit of the consolidated financial
statements and, in our opinion, based on our audit, fairly states, in all
material respects, the financial data required to be set forth therein in
relation to the consolidated financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Washington, D.C.
January 12, 1999
F-1
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(in thousands)
December 31, December 31,
1998 1997
------------ ------------
ASSETS
- ------
Current assets:
Cash and cash equivalents ................. $ 1,839 $ 1,337
Restricted funds .......................... 4,185 6,509
Accounts receivable ....................... 14,281 17,764
Due from affiliates ....................... 743 14
Fuel inventory and supplies ............... 5,033 4,936
Other current assets ...................... 333 338
------------ ------------
Total current assets .................. 26,414 30,898
Plant and equipment ......................... 371,202 371,285
Less: Accumulated depreciation ............. 62,203 49,748
------------ ------------
Net plant and equipment ................... 308,999 321,537
Long-term restricted funds .................. 28,188 21,494
Deferred financing charges, net
of accumulated amortization of
$5,499 at December 31, 1998 and
$4,336 at December 31, 1997 ............... 10,782 11,945
------------ ------------
Total Assets $ 374,383 $ 385,874
============ ============
LIABILITIES AND PARTNERS' CAPITAL
- ---------------------------------
Current liabilities:
Accounts payable .......................... $ 617 $ 1,663
Accrued expenses .......................... 12,614 15,047
Due to affiliates ......................... 639 498
Current portion of long-term bonds ........ 4,822 3,298
------------ ------------
Total current liabilities ............. 18,692 20,506
Deferred revenues ........................... 6,565 ---
Other long-term liabilities ................. 14,803 11,695
Long-term bonds, less current portion ....... 381,133 385,955
Commitments and contingencies (Note 6)
General partners' capital ................... (457) (311)
Limited partners' capital ................... (46,353) (31,971)
------------ ------------
Total partners' capital ............... (46,810) (32,282)
------------ ------------
Total Liabilities and Partners' Capital $ 374,383 $ 385,874
============ ============
The accompanying notes are an integral part of these consolidated financial
statements.
F-2
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
For the For the For the
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
1998 1997 1996
------------ ------------ ------------
Operating revenues:
Electric and steam ................................ $ 158,805 $ 157,940 $ 149,793
Gas resale ........................................ 7,181 13,643 24,649
------------ ------------ ------------
Total operating revenues ...................... 165,986 171,583 174,442
Cost of revenues:
Fuel costs ........................................ 82,392 90,526 89,177
Other operating and maintenance expenses .......... 17,594 18,103 17,913
Depreciation ...................................... 12,501 12,676 12,657
------------ ------------ ------------
Total cost of revenues ........................ 112,487 121,305 119,747
------------ ------------ ------------
Gross profit ........................................ 53,499 50,278 54,695
Other operating expenses:
Administrative services - affiliates .............. 1,931 2,852 2,715
Other general and administrative expenses ......... 2,036 2,562 2,781
Amortization of deferred financing charges ........ 1,163 1,170 1,173
------------ ------------ ------------
Total other operating expenses ................ 5,130 6,584 6,669
------------ ------------ ------------
Operating income .................................... 48,369 43,694 48,026
Interest (income) expense:
Interest income ................................... (2,298) (2,325) (1,956)
Interest expense .................................. 34,346 34,559 34,800
------------ ------------ ------------
Net interest expense .......................... 32,048 32,234 32,844
------------ ------------ ------------
Net Income .......................................... $ 16,321 $ 11,460 $ 15,182
============ ============ ============
Allocated to:
General partners .................................. $ 163 $ 115 $ 152
Limited partners .................................. 16,158 11,345 15,030
------------ ------------ ------------
Total ......................................... $ 16,321 $ 11,460 $ 15,182
============ ============ ============
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
For the years ended December 31, 1998, 1997 and 1996
(in thousands)
General Limited
Partners Partners Total
---------- ---------- ----------
Balance at December 31, 1995 ..... $ 43 $ 1,487 $ 1,530
Cash distributions ............. (368) (35,154) (35,522)
Net income ..................... 152 15,030 15,182
---------- ---------- ----------
Balance at December 31, 1996 ..... (173) (18,637) (18,810)
---------- ---------- ----------
Cash distributions ............. (253) (24,679) (24,932)
Net income 115 11,345 11,460
---------- ---------- ----------
Balance at December 31, 1997 ..... (311) (31,971) (32,282)
---------- ---------- ----------
Cash distributions ............. (309) (30,540) (30,849)
Net income ..................... 163 16,158 16,321
---------- ---------- ----------
Balance at December 31, 1998 ..... $ (457) $ (46,353) $ (46,810)
========== ========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
For the For the For the
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
1998 1997 1996
------------ ------------ ------------
Net cash provided by (used in) operating activities:
Net income ......................................... $ 16,321 $ 11,460 $ 15,182
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Provision for SOP 98-5 ........................... 214 --- ---
Depreciation and amortization .................... 13,664 13,846 13,830
Change in assets and liabilities:
Restricted funds ............................... (1,696) (483) (38)
Accounts receivable ............................ 3,483 2,135 (2,582)
Due from affiliates ............................ (729) 26 (23)
Fuel inventory and supplies .................... (97) (535) (828)
Other current assets ........................... 5 111 563
Accounts payable ............................... (1,046) 1,075 216
Accrued expenses ............................... (2,433) (1,577) 3,376
Due to affiliates .............................. 141 (439) 675
Deferred revenues .............................. 6,565 --- ---
Other long-term liabilities .................... 3,108 1,017 2,163
------------ ------------ ------------
Total adjustments .......................... 21,179 15,176 17,352
------------ ------------ ------------
Net cash provided by
operating activities ................... 37,500 26,636 32,534
Cash flows provided by (used in) investing activities:
Plant and equipment additions ...................... (177) 16 (601)
------------ ------------ ------------
Net cash provided by (used in)
investing activities ................... (177) 16 (601)
Cash flows provided by (used in) financing activities:
Restricted funds ................................... (2,674) (790) 4,224
Cash distributions to partners ..................... (30,849) (24,932) (35,522)
Payments of principal on long-term debt ............ (3,298) (2,167) (580)
Advances from a customer ........................... --- (17) (136)
------------ ------------ ------------
Net cash used in
financing activities ................... (36,821) (27,906) (32,014)
Net increase (decrease) in cash ...................... 502 (1,254) (81)
Cash at beginning of period .......................... 1,337 2,591 2,672
------------ ------------ ------------
Cash at end of period ................................ $ 1,839 $ 1,337 $ 2,591
============ ============ ============
Supplemental disclosures of cash flow information:
Cash paid for interest ............................. $ 34,349 $ 34,561 $ 34,781
============ ============ ============
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997
1. Organization and business
-------------------------
Selkirk Cogen Partners, L.P. (the Partnership) was organized on
December 15, 1989 as a Delaware limited partnership. Prior to the
Partnership agreement, the partners had a cost sharing arrangement for
costs incurred from the project's inception in October 1987. See Note 3
for a discussion of the general and limited partners and their
respective equity interests.
Selkirk Cogen Funding Corporation (Funding Corporation) was organized
as a wholly-owned subsidiary of the Partnership for the sole purpose of
facilitating financing activities of the Partnership (see Note 4). The
Funding Corporation has no operations. All of the issued and
outstanding capital stock of the Funding Corporation is owned by the
Partnership. The obligations of the Funding Corporation in respect of
the bonds are unconditionally guaranteed by the Partnership. The
financial statements of the Partnership and the Funding Corporation are
prepared on a consolidated basis.
JMCS I Management, Inc., an affiliate of the Managing General Partner,
JMC Selkirk, Inc. is acting as the project management firm for the
Partnership, and as such is responsible for the implementation and
administration of Partnership's business under the direction of the
Managing General Partner. All of the officers and directors of the JMC
Selkirk, Inc. and Funding Corporation are also officers of JMCS I
Management, Inc.
The Partnership was formed for the purpose of constructing, owning and
operating a natural gas-fired combined-cycle cogeneration facility
located on General Electric Company's (General Electric) property in
Bethlehem, New York (the Facility). The Facility consists of one unit
(Unit 1), with an electric generating capacity of approximately 79.9
megawatts (MW) and a second unit (Unit 2), with an electric generating
capacity of approximately 265 MW. Unit 1 and Unit 2 have been designed
to operate independently for electrical generation, while thermally
integrated for steam generation, thereby optimizing efficiencies in the
combined performance of the Facility. The Partnership received
construction financing for Unit 1 in June 1990 and commercial
operations commenced on April 17, 1992. Unit 2 obtained construction
financing in October 1992 and commercial operations commenced September
1, 1994. Both Units are fueled by Canadian natural gas purchased under
firm 15-year natural gas supply contracts (extendible to 20 years upon
satisfaction of certain conditions). Prior to June 30, 1998, Unit 1
sold at least 79.9 MW of electric capacity and associated energy to
Niagara Mohawk Power Corporation (Niagara Mohawk) under a 20-year
contract. On August 31, 1998 the Partnership and Niagara Mohawk
executed an Amended and Restated Niagara Mohawk Power Purchase
Agreement.
F-6
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The term of the Amended and Restated Niagara Mohawk Power Purchase
Agreement is ten years from June 30, 1998. The Amended and Restated
Niagara Mohawk Power Purchase Agreement transfers dispatch
decision-making authority of at least 79.9 MW of electric capacity and
associated energy from Niagara Mohawk to the Partnership. Unit 2 is
selling 265 MW of electric capacity and associated energy to
Consolidated Edison Company of New York (Con Edison) under a 20-year
contract. Also, the Partnership makes excess gas lay-off sales during
periods when Units 1 and 2 are not operating at full capacity (see Note
6). However, historical natural gas resale prices have resulted in
significant gas resale margins for the Partnership. Historical natural
gas prices may not be indicative of future natural gas market prices.
The Facility is currently certified as a qualifying facility (Qualifying
Facility) under the Public Utility Regulatory Policy Act of 1978, as
amended (PURPA). Accordingly, the prices charged for the sale of
electricity and steam are not regulated. When Unit 2 commenced
operations, the Facility was no longer qualified by the State of New
York but continues to be certified by the Federal Energy Regulatory
Commission (FERC) as a Qualifying Facility. However, this is not
expected to have a material impact on the Partnership's financial
position or operations. Certain fuel transportation agreements entered
into by the Partnership are subject to regulation on the federal and
provincial levels in Canada. The Partnership has obtained all material
Canadian governmental permits and authorizations required for operation.
2. Summary of significant accounting policies
------------------------------------------
Basis of presentation
---------------------
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ
from those estimates.
Principles of consolidation
---------------------------
The consolidated statements of operations for the years ended December
31, 1998, 1997 and 1996 include the activities of the Funding
Corporation. All intercompany balances and transactions have been
eliminated in consolidation.
F-7
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Cash and cash equivalents
-------------------------
The Partnership considers all non restricted liquid securities with an
original maturity of three months or less to be cash equivalents.
Restricted funds and long-term restricted funds
-----------------------------------------------
All cash and cash equivalents are restricted as to their use under the
Deposit and Disbursement Agreement. Certain of the Restricted funds are
associated with transactions or events which are applicable to periods
beyond the current accounting period and are, therefore, classified as
long-term. All other Funds are classified as current assets (See Note
4).
Fuel inventory and supplies
---------------------------
Inventories are stated at the lower of cost or market. Costs for
materials, supplies and fuel oil inventories were determined on an
average cost method.
Plant and equipment
-------------------
Plant and equipment is stated at cost, net of accumulated depreciation.
Depreciation is computed on a straight-line basis over the estimated
useful lives of the related assets as follows:
Cogeneration facility 30 years
Computer systems 7 years
Office equipment 5 years
A major overhaul reserve is recorded based upon the costs for periodic
overhauls of major systems within the Facility. Major overhauls are
required on a multiple-year cycle basis. The major overhaul reserve is
included in other long-term liabilities in the balance sheet and had a
carrying amount of approximately $6,543,000 and $5,105,000 at December
31, 1998 and 1997, respectively. The provision charged for the
maintenance and repairs reserve is included in other operating and
maintenance expenses in the in the consolidated statements of
operations. The provision charged for the major overhaul reserve during
the years ended December 31, 1998, 1997 and 1996 was $1,814,000,
$1,800,576 and $1,800,576, respectively. Other maintenance and repairs
are charged to expense as incurred.
F-8
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Deferred financing charges
--------------------------
Deferred financing charges relate to costs incurred to issue long-term
obligations and are amortized using the effective interest rate method
over the lives of the loans to which they pertain.
Accrued expenses
----------------
Accrued expenses consist of the following (in thousands):
December 31, December 31,
1998 1997
------------ ------------
Accrued fuel costs $ 8,130 $ 10,002
Accrued PILOT 1,250 1,150
Accrued utilities 852 924
Accrued plant purchases 75 391
Accrued bond interest 379 382
Accrued GE steam refund 506 668
Other accrued expenses 1,422 1,530
----------- ------------
$ 12,614 $ 15,047
=========== ============
Real estate taxes
-----------------
Real estate tax payments made under the Partnership's payment in lieu
of taxes (PILOT) agreement are recognized on a straight-line basis over
the term of the agreement.
Deferred revenues
-----------------
The net cash receipts and restructuring costs resulting from the
execution of the Amended and Restated Niagara Mohawk Power Purchase
Agreement are being deferred to be amortized over the ten year term of
the Amended and Restated Power Purchase Agreement (See Note 6).
Currency swap agreements
------------------------
In connection with its asset and liability management policies, the
Partnership entered into foreign currency swap agreements as discussed
in Note 4. Gains and losses on currency exchange contracts are deferred
as hedges of firmly committed transactions and recognized in income in
the same period that the hedged transactions are realized. In the
unlikely event that the underlying transaction terminates, the deferred
gains and
F-9
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
losses on the associated swap agreement will be recorded in the
consolidated statements of operations.
Revenue recognition
-------------------
Revenues for the sale of electricity and steam are recorded based on
monthly output delivered as specified under contractual terms. Revenues
for the sale of excess gas are recorded in the month sold.
Income taxes
------------
The tax results of Partnership activities flow directly to the partners;
thus, the accompanying consolidated financial statements do not reflect
provisions for federal or state income taxes.
New accounting pronouncements
-----------------------------
During 1997, the Financial Accounting Standards Board (FASB) issued two
new accounting standards. Statement of Financial Accounting Standards
(SFAS) No. 130, "Reporting Comprehensive Income" requires disclosure on
comprehensive income and its components. SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information" requires
disclosure of financial and descriptive information on reportable
operating segments. The Partnership adopted SFAS No. 130 and SFAS No.
131 during 1998. The adoption of these accounting principles had no
material impact on the Partnership.
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 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. The Partnership adopted SOP 98-5 in November 1998, and recorded a
charge to write-off capitalized start-up costs of approximately $214,000
in other general and administrative expenses of the consolidated
statements of operations.
In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities. SFAS No. 133 establishes accounting
and reporting standards requiring that every derivative instrument be
recorded in the balance sheet as either an
F-10
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
asset or liability measured at its fair value. Changes in the
derivatives fair value must be recognized in the statement of operations
as a gain or loss unless specific hedge accounting criteria are met.
SFAS No. 133 is effective for fiscal years beginning after June 15,
1999. SFAS No. 133 must be applied to (a) derivative instruments and (b)
certain derivative instruments embedded in hybrid contracts. Management
has not yet quantified the impact of adopting SFAS No. 133 on the
Partnership's financial statements.
3. Partners' capital
-----------------
In June 1995, the partnership agreement was amended to reflect
conversion of the general partnership interest in the Partnership held
by JMCS I Investors, L.P. (now known as PentaGen Investors, L.P.
(Investors)) to a limited partnership interest and the assignment of a
portion of Investors limited partnership interest in the Partnership to
JMC Selkirk, Inc.
The general and limited partners, along with their respective equity
interests are as follows:
Interest
General partners Affiliate of Preferred Original
----------------- ------------- --------- --------
JMC Selkirk, Inc. Beale Generating Company (Beale)* .09% 1.00%
Cogen Technologies
Selkirk GP, Inc. Cogen Technologies, Inc. 1.00% ---%
Interest
Limited partners Affiliate of Preferred Original
---------------- ------------ --------- --------
JMC Selkirk, Inc. Beale Generating Company 1.95% 21.40%
PentaGen Investors, L.P. Beale Generating Company 5.25% 57.60%
EI Selkirk, Inc. GPU International, Inc. (GPUI) 13.55% 20.00%
Cogen Technologies
Selkirk LP, Inc. Cogen Technologies, Inc. 78.16% ---%
*Formerly known as J. Makowski Company, Inc.
Under the terms of the amended partnership agreement, cash available is
first distributed 99% to the partners in accordance with their
respective equity interests (preferred equity) and 1% is allocated based
on the original ownership structure between Beale affiliates and GPUI.
Any additional funds available after the preferred
F-11
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
distribution, are distributed 99% to the original equity holders and 1%
to the preferred equity holders. Subsequent to the eighteenth
anniversary of Unit 2's commercial operations or the date on which all
the preferred partners achieve a specified return, distributions will be
made in accordance with the residual interest; Beale affiliates at
64.8%, GPUI at 17.7% and Cogen Technologies, Inc. at 17.5%.
4. Debt financing
--------------
On May 9, 1994, the Funding Corporation issued an aggregate of
$392,000,000 in bonds of which a portion was used to refinance the
outstanding indebtedness of the Partnership. The bonds consist of
$165,000,000 which matures on December 26, 2007 at an interest rate of
8.65% with principal and interest payable semi-annually on June 26 and
December 26 of each year with principal payments commencing June 26,
1996 and $227,000,000 which matures on June 26, 2012 at an interest rate
of 8.98% with principal and interest payable semi-annually on June 26
and December 26 of each year with principal payments commencing December
26, 2007.
The scheduled principal payments on the bonds are as follows:
1999 4,822,151
2000 7,306,785
2001 11,062,070
2002 13,528,965
2003 17,365,291
Thereafter 331,870,094
The loans are secured by liens on, and security interests in,
substantially all of the assets of the Partnership. These loans are
non-recourse to the individual partners. The trust indenture restricts
the ability of the Partnership to make distributions to the partners
under certain circumstances.
In connection with the sale of the Bonds, the Partnership entered into
the Deposit and Disbursement Agreement (the D&D Agreement) which
requires the establishment and maintenance of certain segregated funds
(the Funds) and is administered by Bankers Trust Company, as depositary
agent. Pursuant to the D&D Agreement a number of Funds were established.
Some of the Funds have been terminated since the purposes of such Funds
were achieved and are no longer required, some Funds are currently
active and some Funds activate at future dates upon the occurrence of
certain events. The significant Funds that are currently active and
included in restricted funds in the consolidated balance sheets are the
Project Revenue Fund, Principal Fund, Interest Fund, and two sub-funds
of the Partnership Distribution Fund. The significant Funds
F-12
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
that are currently active and included in long-term restricted funds in
the consolidated balance sheets are the Major Maintenance Reserve Fund
and Debt Service Reserve Fund.
All Partnership cash receipts and operating cost disbursements flow
through the Project Revenue Fund. As determined on the 20th of each
month, any monies remaining in the Project Revenue Fund after the
payment of operating costs are used to fund the above named Funds based
upon the Fund hierarchy and in the amounts (each, a Fund Requirement)
established pursuant to the D&D Agreement.
The Major Maintenance Reserve Fund relates to certain anticipated annual
and periodic major maintenance to be performed on certain of the
Facility's machinery and equipment at future dates. The Fund Requirement
is developed by the Partnership and approved by an independent engineer
for the Trustee and can be adjusted on an annual basis, if needed. At
December 31, 1998 the balance in this Fund was approximately $5,634,585,
which exceeded the current Fund Requirement of $4,385,000.
The Interest and Principal Funds relate primarily to the current debt
service on the outstanding Bonds. The applicable Fund Requirement is the
amount due and payable on the next semi-annual payment date. On December
26, 1998, the monies available in the Interest and Principal Funds were
used to make the semi-annual interest and principal payments. Therefore,
the balance in the Interest and Principal Funds at December 31, 1998
were $0. The June 26, 1999 Interest and Principal Fund Requirements will
be approximately $17,067,119 and approximately $2,023,469, respectively.
The Fund Requirement for the Debt Service Reserve Fund is an amount
equal to the maximum amount of debt service due in respect of all the
Bonds outstanding for any six-month period during the succeeding
three-year period. At December 31, 1998 the balance in this Fund was
approximately $22,553,143. The June 26, 1999 Fund Requirement will
remain at approximately $22,553,143.
The Partnership Distribution Fund is at the end of the Fund hierarchy
and cash distributions to the Partners from these sub-funds can only be
made upon the achievement of specific criteria established pursuant to
the financing documents, including the D&D Agreement. This Fund does not
have a Fund Requirement.
In 1994, the Partnership entered into a combined working capital and
bank reimbursement agreement, as amended (Credit Agreement). The Credit
Agreement has a maximum available amount of $10,389,528 to be used by
the Partnership for required letters of credit related to various
project contracts and for working capital
F-13
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
purposes. The maximum amount available under the Credit Agreement for
working capital purposes is $5,000,000. At December 31, 1998, no draws
had been made against the outstanding letters of credit and no working
capital loans were outstanding under the Credit Agreement. The Credit
Agreement expires on August 1, 2001.
Currency swap agreements
------------------------
On June 20, 1990 and October 29, 1992, the Partnership entered into
currency exchange agreements to hedge against future exchange rate
fluctuations which could result in additional costs incurred under fuel
transportation agreements which are denominated in Canadian dollars. The
June 1990 agreement relates to Unit 1 under which the Partnership
exchanges approximately $368,000 U.S. dollars for $458,000 Canadian
dollars on a monthly basis commencing on December 25, 1992 and
terminating December 25, 2002. The October 1992 agreement relates to
Unit 2 under which the Partnership exchanges approximately $1,044,000
U.S. dollars for $1,300,000 Canadian dollars on a monthly basis
commencing on May 25, 1995 and terminating December 25, 2004. During the
years ended December 31, 1998, 1997 and 1996 fuel costs were higher by
approximately $2,480,428, $1,513,559 and $1,313,613, respectively as a
result of the currency exchange agreements.
The Partnership is exposed to credit loss under the currency agreements.
In the unlikely event that a counterparty fails to meet the terms of the
agreements, the Partnership's exposure is limited to the currency
exchange rate differential. However, the Partnership does not anticipate
nonperformance by the counterparties.
5. Disclosure of fair value of financial instruments
-------------------------------------------------
The following methods and assumptions were used by the Partnership in
estimating its fair value disclosures for financial instruments as of
December 31, 1998 and 1997:
Cash and cash equivalents: The carrying amount reported in the
accompanying balance sheets for cash approximates its fair value of
$1,839,000 and $1,337,000 at December 31, 1998 and 1997, respectively
due to the short-term maturities of these amounts.
Restricted funds: The carrying amount reported in the accompanying
balance sheets for restricted funds approximates its fair value of
$32,373,000 and $28,003,000 at December 31, 1998 and 1997, respectively.
F-14
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Accounts receivable: The carrying amount reported in the accompanying
balance sheets for accounts receivable approximates its fair value due
to the short-term maturities of these amounts.
Due from affiliates: The carrying amount reported in the accompanying
balance sheets for amounts due from affiliates approximates its fair
value due to the short-term maturities of these amounts.
Due to affiliates: The carrying amount reported in the accompanying
balance sheets for amounts due to affiliates approximates its fair
value due to the short-term maturities of these amounts.
Accounts payable: The carrying amount reported in the accompanying
balance sheets for accounts payable approximates its fair value due to
the short-term maturities of these amounts.
Long-term bonds: The fair value of the long-term bonds is based on the
current market rates for the bonds. The fair value of the long-term
bonds (including the current portion) at December 31, 1998 and 1997 is
approximately $420,252,063 and $404,282,956, respectively.
Currency swap agreements: The carrying value of the currency exchange
agreements at December 31, 1998 and 1997 is $0. The fair value of the
currency exchange arrangements represents the termination liability of
approximately $11,911,000 and $10,535,000 at December 31, 1998 and
1997, respectively, estimated using current exchange rates.
6. Commitments
-----------
The Partnership has entered into site lease, property tax, fuel supply
and transportation, power sales, steam sales, electric interconnection
and transmission, operations and maintenance, water supply and project
administrative agency agreements. In connection with the construction
and operation of the Facility, the Partnership is obligated under the
following agreements:
Power Purchase Agreements - electricity
---------------------------------------
In December 1987, the Partnership entered into a power purchase
agreement, as amended, with Niagara Mohawk, for the sale of
electricity, for an initial term of 20 years commencing on the date of
commercial operations, April 17, 1992.
F-15
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
In April 1994, the power purchase agreement with Niagara Mohawk was
amended and, pursuant to this amended agreement, the Partnership paid
Niagara Mohawk $1,250,000 as a consent fee from the proceeds of the bond
offering. In addition, the Partnership posted a letter of credit for
approximately $15,000,000 under the Credit Agreement.
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).
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. 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). On February 24, 1998, the NYPSC approved Niagara
Mohawk's Power Choice settlement proposal, including the implementation
of the MRA.
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). 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.
Pursuant to the terms of the MRA, the closing of the MRA transactions
between the Partnership and Niagara Mohawk was deferred until August 31,
1998.
On August 31, 1998 the Partnership and Niagara Mohawk consummated the
transactions relating to the Amended and Restated Niagara Mohawk Power
Purchase Agreement pursuant to the MRA. As contemplated by the MRA, on
that date (i) the Partnership notified Niagara Mohawk of the
Partnership's determination that the requirements of the Partnership's
Trust Indenture, dated as of May 1, 1994 (the Indenture), with respect
to the restructuring of certain project contracts relating to the
operation of Unit 1 of the Selkirk facility had been satisfied; (ii) the
Amended and Restated Power Purchase Agreement, dated as of July 1, 1998,
between the Partnership and Niagara Mohawk became effective; and (iii)
Niagara Mohawk made
F-16
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
as its net share of the agreed allocation among IPP's for certain
adjustments, cash payments of approximately $10.3 million into the
Partnership's Project Revenue Fund maintained at Bankers Trust Company,
as Depositary Agent under the May 1, 1994 Deposit and Disbursement
Agreement. In addition, the Partnership delivered notices to Paramount
Resources Limited (Paramount) and TransCanada Pipelines Limited
(TransCanada) that the Second Amended and Restated Gas Purchase
Contract, dated as of May 6, 1998, between the Partnership and
Paramount, and the Amending Agreement to Gas Transportation Contract,
dated as of July 20, 1998, between the Partnership and TransCanada had
become effective.
The term of the Amended and Restated Niagara Mohawk Power Purchase
Agreement is ten years from June 30, 1998. The $2,211,000 payment made
by the Partnership to Niagara Mohawk and the $10,354,000 of payments
received by the Partnership from Niagara Mohawk (representing net
receipts to the Partnership of approximately $8,143,000) were a
condition to the Amended and Restated Niagara Mohawk Power Purchase
Agreement and are being deferred to be amortized over the ten year term
of the Amended and Restated Power Purchase Agreement. In addition,
approximately $1,233,000 in restructuring costs will also be amortized
over the ten-year term of the Amended and Restated Niagara Mohawk Power
Purchase Agreement. Deferred Revenues of approximately $6,565,000 appear
on the balance sheet at December 31, 1998. As a result of the execution
of the Amended and Restated Niagara Mohawk Power Purchase Agreement, the
Partnership is no longer required to post a letter of credit for
approximately $15,000,000 under the Credit Agreement.
On August 31, 1998, the Partnership received written notice from
Standard & Poor's Corporation (S&P) that, after giving effect to the
consummation of the transactions contemplated by the Amended and
Restated Niagara Mohawk Power Purchase Agreement, S&P affirmed its
"BBB-" rating of the Selkirk Cogen Funding Corporation's Bonds and
removed the rating from CreditWatch. On August 27, 1998, the Partnership
received written notice from Moody's Investors Service, Inc. (Moody's)
that, after giving effect to the Unit 1 Restructuring, Moody's affirmed
its "Baa3" rating of the Selkirk Cogen Funding Corporation's Bonds,
changed the outlook of the Bonds Due 2007 from "negative" to "stable"
and has not changed its previous "negative outlook" with respect to the
Bonds Due 2012.
The Amended and Restated Niagara Mohawk Power Purchase Agreement
transfers dispatch decision-making authority from Niagara Mohawk to the
Partnership. In effect, Unit 1 will operate on a "merchant-like" basis,
whereby the Partnership will have the ability and flexibility to
dispatch Unit 1 based on, then current, market conditions.
F-17
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The Partnership has also entered into a power purchase agreement with
Con Edison, for the sale of electricity, for an initial term of 20
years commencing on September 1, 1994, the date of Unit 2 commercial
operations. The contract is extendible under certain circumstances.
On February 6, 1995, the Partnership provided Con Edison with a letter
of credit in the amount of approximately $1,046,000. The letter of
credit represented security pursuant to Article 13 of the Con Edison
power purchase agreement and expired on February 6, 1996.
The power purchase agreement with Con Edison provides the purchasing
utility with the contractual right to schedule Unit 2 for dispatch on a
daily basis at full capability, partial capability or off-line. Con
Edison's scheduling decisions are required to be based in part on
economic criteria which, pursuant to the governing rules of the New
York Power Pool, take into account the variable cost of the electricity
to be delivered. Certain payments under these agreements are unaffected
by levels of dispatch. However, certain payments may be rebated or
reduced to Con Edison if the Partnership does not maintain a minimum
availability level.
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.
F-18
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
On July 21, 1998 the 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.
In August 1992, Niagara Mohawk filed a petition requesting the NYPSC to
authorize Niagara Mohawk to curtail purchases from, and avoid payment
obligations to, non-utility generators, including Qualifying Facility's
such as the Facility during certain periods. Niagara Mohawk claimed
that such curtailment would be consistent with PURPA, and the
regulations promulgated thereunder, which contemplates utilities'
curtailing purchases from Qualifying Facility's under certain
circumstances. In October 1992, the NYPSC initiated a proceeding to
investigate whether conditions existed justifying the exercise of the
PURPA curtailment rights and, if so, to determine the procedures for
implementing PURPA curtailment rights. Con Edison also filed a petition
in this proceeding seeking to implement PURPA curtailment rights during
certain periods. An administrative law judge appointed by the NYPSC
held hearings during the spring of 1993, however, his opinion was never
released. On August 30, 1996, the NYPSC reopened the curtailment
proceedings and directed an administrative law judge to prepare a
recommended decision under an abbreviated deadline. On March 18, 1998,
the NYPSC announced that an order instituting a curtailment policy
would be forthcoming, however, a written order has not yet been issued.
In conjunction with the execution of the Amended and Restated Niagara
Mohawk Power Purchase Agreement on August 31, 1998 Niagara Mohawk
waived any rights to curtail purchases from the Partnership.
With respect to the Con Edison petition, the Partnership has taken the
position in this proceeding that it should not be subject to
curtailment as a result of this proceeding, even if the NYPSC grants
Con Edison some measure of generic curtailment rights. The
Partnership's position is based in part on the fact that Con Edison did
not bargain for an express curtailment right in its Power Purchase
Agreement and the Partnership agreed to permit Con Edison to direct the
dispatch of Unit 2. Nevertheless, Con Edison has refused to expressly
waive its claimed curtailment rights against
F-19
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
dispatchable facilities and has not agreed to exempt the Facility from
curtailment, notwithstanding the absence of contractual language in the
Power Purchase Agreement granting the utility this right. If Con Edison
was to receive NYPSC authorization to curtail power purchases from
Qualifying Facilities including dispatchable facilities, it may seek to
implement curtailment with respect to the Partnership by avoiding not
only energy payments but also capacity payments during periods in which
the Facility is curtailed. Such a reduction in energy payments and
capacity payments could materially and adversely affect the
Partnership's net operating revenues.
Steam sales agreements
----------------------
In February 1990, the Partnership entered into a steam sales agreement
for Unit 1, as amended, with General Electric for an initial term of 20
years, effective from the date of commercial operations. On October 21,
1992, the Partnership and General Electric entered into a new steam
sales agreement, as amended with a term of 20 years from the commercial
operations date of Unit 2 and may be extended under certain
circumstances. The Unit 1 steam sales agreement terminated upon the
commercial operations of Unit 2.
Until Unit 2 achieved commercial operations, General Electric had agreed
to forego (subject to later repayment plus interest) the discount on a
certain quantity of steam supplied by the Partnership during a quarter
to the extent necessary for the Partnership to maintain a quarterly debt
service coverage ratio of 1.2 to 1 and the advances, with interest, are
repayable to the extent the Partnership's quarterly debt service
coverage ratio exceeds 1.3 to 1. Under this agreement, the Partnership
had invoiced and received from General Electric approximately $899,000
and $4,123,000 at December 31 and March 31, 1994, respectively. In April
1995, the Partnership paid off the outstanding principal amount and
approximately 75% of the associated accrued interest. The Partnership
paid the remaining accrued interest in January 1996 and February 1997.
General Electric is obligated under the steam sales agreement to
purchase the minimum quantities of steam necessary for the Facility to
maintain its Qualifying Facility status. In the event that General
Electric were to fail to purchase and take this minimum quantity, the
Partnership could acquire title to the Facility Site, terminating the
Lease Agreement, at no cost to the Partnership.
The agreement provides General Electric the right of first refusal to
purchase the Facility, subject to certain pricing considerations.
Additionally, General Electric has the right to purchase the boiler
facility that produces the steam at a mutually agreed upon price if and
when the steam sale agreement is terminated. The steam sales
F-20
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
agreement may be terminated by the Partnership with one year's written
notice if either the Niagara Mohawk or Con Edison power purchase
agreement is terminated. It may also be terminated by General Electric
with two years' written notice if General Electric's plant no longer has
a requirement for steam.
Fuel supply and transportation agreements
-----------------------------------------
The Partnership has entered into a firm natural gas supply agreement, as
amended, with Paramount Resources Ltd., a Canadian corporation, for Unit
1. The agreement has an initial term of 15 years which began in November
1992, with an option to extend for an additional 4 years upon
satisfaction of certain conditions.
The Partnership entered into firm natural gas supply agreements with
various suppliers for Unit 2. The agreements have an initial term of 15
years, which began November 1, 1994, and an option to extend for an
additional 5-year term upon satisfaction of certain conditions.
Each Unit 2 gas supply contract requires that the Partnership purchase a
minimum of 75% of the maximum annual contract volumes each year. If the
Partnership fails to take this minimum quantity, then the shortfall
amount between the minimum required volumes and the actual nominations
must be made up in the following year(s). The Partnership is allowed up
to two years under these contracts during which time the Partnership may
make up any shortfall. If the Partnership does not make up the shortfall
within these periods, then the suppliers have a right to reduce the
maximum daily contract quantity by the shortfall. The Partnership
purchased approximately $32,048,000, $38,279,000 and $35,191,000 in gas
from these suppliers for the years ended December 31, 1998, 1997 and
1996, respectively.
The Partnership has entered three 20-year agreements for firm fuel
transportation service to supply Unit 1 commencing November 1, 1992. In
accordance with one of these agreements, the Partnership posted a letter
of credit in the amount of approximately $586,000 in October 1992.
The Partnership has entered into three agreements for firm fuel
transportation service for Unit 2. The agreements commenced in November
1994 and have terms of 20 years. The Partnership and two fuel suppliers
on behalf of the Partnership have posted letters of credit totaling
approximately $9,721,000 Canadian dollars for the benefit of the
transporter. The Partnership will reimburse all costs related to
obtaining and maintaining the letters of credit. The Partnership also
posted two letters of credit related to the remaining two firm fuel
transportation agreements for approximately $796,000 and $2,090,000.
F-21
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
During the first quarter of 1997, the FERC approved a settlement
between the Partnership and one of its fuel transporters. The
settlement was beneficial to the Partnership in that the Partnership
received refunds for reductions in rates and established a mechanism
whereby future rates would step down. During the years ended December
31, 1998 and 1997, fuel costs were reduced by approximately $0.9
million and $1.8 million, respectively as a result of the FERC approved
settlement.
Electric interconnection and transmission agreements
----------------------------------------------------
The Partnership constructed an interconnection facility to transfer
power from Unit 1 to Niagara Mohawk and transferred title of the
facility to Niagara Mohawk. The Partnership has agreed to reimburse
Niagara Mohawk $150,000 annually for the operation and maintenance of
the facility. The term of the agreement is for 20 years from the
commercial operations date of Unit 1 and may be extended if the power
purchase agreement with Niagara Mohawk is extended.
In December 1990, the Partnership entered into a 20-year firm
interruptible transmission agreement with Niagara Mohawk, as amended,
to transmit power from Unit 2 to Con Edison, beginning with commercial
operations. In connection with this agreement, the Partnership
constructed an interconnection facility and transferred title to
Niagara Mohawk in 1995. Under the terms of this agreement, the
Partnership will reimburse Niagara Mohawk $450,000 annually for the
maintenance of the facility.
Site lease
----------
Rent expense was approximately $1,000,000, for the years ended December
31, 1998, 1997 and 1996. The amended lease term expires on the
twentieth anniversary of the commercial operations date of Unit 2 and
is renewable for the greater of 5 years or until termination of any
power sales contract, to a maximum of 20 years. The lease may be
terminated by the Partnership under certain circumstances with the
appropriate written notice during the initial term.
Payment in lieu of taxes agreement
----------------------------------
In October 1992, the Partnership entered into a payment in lieu of
taxes (PILOT) agreement with the Town of Bethlehem Industrial
Development Agency (IDA), a corporate governmental agency, which
exempts the Partnership from all property taxes, except for special
assessments. The agreement commenced on January 1, 1993, and terminates
on December 31, 2012.
F-22
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
On the closing date of the facility lease agreement with the IDA, the
Partnership paid the IDA $250,000 as one half of a $500,000 financing
fee; the second installment was paid upon completion of Unit 2 and
issuance by the Town of Bethlehem of a final certificate of occupancy.
PILOT payments are due semi-annually in equal installments and are
scheduled for the years as follows:
1999 $ 2,500,000
2000 2,700,000
2001 2,900,000
2002 3,100,000
2003 3,300,000
Thereafter 35,900,000
Other agreements
----------------
The Partnership has an operations and maintenance services agreement
with General Electric whereby General Electric will provide certain
operation and maintenance services during the operations of Unit 1 and
the construction of Unit 2 and for seven (7) years after the Unit 2
commercial operations date on a cost plus fixed fee basis. In addition,
the Partnership has entered into a 20-year take or pay water supply
agreement with the Town of Bethlehem under which the Partnership is
committed to make minimum annual purchases of approximately $1,000,000,
subject to adjustment for changes in market rates beginning in the
tenth year.
7. Related parties
---------------
JMCS I Management, an affiliate of JMC Selkirk, Inc. has been appointed
project administrative agent to manage the day-to-day affairs of the
Partnership. This affiliate is compensated at agreed-upon billing rates
which are adjusted quadrennially in accordance with an administrative
services agreement. For the years ended December 31, 1998, 1997 and
1996 approximately $2,651,000, $2,852,000 and $2,715,000, respectively
were incurred for services rendered. During the year ended December 31,
1998 approximately, $720,000 of legal and financial consulting services
were capitalized in conjunction execution of the Niagara Mohawk Power
Purchase Agreement (See Note 6). These administrative services, net of
capitalized costs are reflected in administrative services - affiliates
in the statement of operations.
During the years ended December 31, 1998, 1997 and 1996, the
Partnership purchased approximately $1,649,000, $346,000 and $16,000,
respectively and sold approximately $1,476,000, $26,000 and $238,000,
respectively in fuel at its fair market value in transactions with
affiliates of JMC Selkirk, Inc. Spot gas purchases
F-23
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
and the net effect of purchases and sales of gas along the pipelines are
included in fuel costs and sales of excess natural gas supplies are
included in gas resales in the statements of operations.
In May 1996, the Partnership entered into an Enabling Agreement with
PG&E Energy Trading - Power, L.P. (formerly US Gen Power Services,
L.P.)., an affiliate of JMC Selkirk, Inc., to enter into certain
transactions for the purchase and sale of electric capacity, electric
energy and other services. During the years ended December 31, 1998,
1997 and 1996, the Partnership entered into energy and capacity sale
transactions with PG&E Energy Trading - Power, L.P. totaling
approximately $2,009,000, $100,000 and $45,000, respectively.
The Partnership has two agreements with Iroquois Gas Transmission System
(IGTS) to provide firm transportation of natural gas from Canada. An
affiliate of JMC Selkirk, Inc. has a partnership interest in IGTS.
F-24
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Additions
-------------------------
Charged
Balance at Charged to to Other Balance at
Beginning Costs and Accounts Deductions End of
Description of Period Expenses Describe Describe Period
- ---------------------------------- ---------- ---------- ---------- ---------- ----------
Deducted from asset account -
allowance for doubtful accounts:
Year Ended
December 31, 1998 $ - $ - $ - $ - $ -
========== ========== ========== ========== ==========
Year Ended
December 31, 1997 $ - $ - $ - $ - $ -
========== ========== ========== ========== ==========
Year Ended
December 31, 1996 $ 87,181 $ - $ - $ 87,181 (1) $ -
========== ========== ========== ========== ==========
(1) Represents the settlement of August and September 1995 capacity payment
issue.
S-1
Exhibit No. Description of Exhibit
3.1(1) Certificate of Incorporation of Selkirk Cogen Funding Corporation
(the "Funding Corporation")
3.2(1) By-laws of the Funding Corporation
3.3(1) Second Amended and Restated Certificate of Limited Partnership of
Selkirk Cogen Partners, L.P. (the "Partnership")
3.4(1) Third Amended and Restated Agreement of Limited Partnership of
the Partnership, dated as of May 1, 1994, among JMC Selkirk, Inc.
("JMC Selkirk"), JMCS I, Investors, L.P. ("JMCS I Investors"),
Makowski Selkirk Holdings, Inc. ("Makowski Selkirk"), Cogen
Technologies Selkirk, LP ("Cogen Technologies LP") and Cogen
Technologies Selkirk GP, Inc. ("Cogen Technologies GP")
3.5(2) Amendment No. 1 to the Third Amended and Restated Agreement of
Limited Partnership of the Partnership, dated as of November 1,
1994
3.6(2) Amendment No. 2 to the Third Amended and Restated Agreement of
Limited Partnership of the Partnership, dated as of June 16, 1995
4.1(1) Trust Indenture, dated as of May 1, 1994, among the Funding
Corporation, the Partnership and Bankers Trust Company, as
trustee (the "Trustee")
4.2(1) First Series Supplemental Indenture, dated as of May 1, 1994,
among the Funding Corporation, the Partnership and the Trustee
4.3(1) Registration Agreement, dated April 29, 1994, among the Funding
Corporation, the Partnership, CS First Boston Corporation, Chase
Securities, Inc. and Morgan Stanley & Co. Incorporated
4.4(1) Partnership Guarantee, dated as of May 1, 1994, of the
Partnership to the Trustee (2007)
4.5(1) Partnership Guarantee, dated as of May 1, 1994, of the
Partnership to the Trustee (2012)
10.1 Credit Facilities
39
10.1.1(1) Credit Bank Working Capital and Reimbursement Agreement, dated as
of May 1, 1994, among the Partnership, The Chase Manhattan Bank,
N.A. ("Chase"), as Agent, and the other Credit Banks identified
therein
10.1.2(1) Amendment No. 1 to Credit Agreement, dated August 11, 1994, among
the Partnership, Dresdner Bank AG, New York Branch, and Chase
10.1.3(6) Amendment No. 2 to Credit Agreement, dated April 7, 1995, between
the Partnership and Dresdner Bank AG, New York Branch
10.1.4(6) Amendment No. 3 to Credit Agreement, dated July 1, 1997, between
the Partnership and Dresdner Bank AG, New York Branch
10.1.5 Amendment No. 4 to Credit Agreement, dated November 16, 1998,
between the Partnership and Dresdner Bank AG, New York Branch
10.1.6(1) Loan Agreement, dated as of May 1, 1994, between the Partnership,
Chase, as Agent, and other Bridge Banks identified therein
10.1.7(1) Amended and Restated Loan Agreement, dated as of May 1, 1994,
between the Funding Corporation and the Partnership
10.1.8(1) Agreement of Consolidation, Modification and Restatement of Notes
($227,000,000), dated as of May 1, 1994, between the Partnership
and the Funding Corporation, together with Endorsement from the
Funding Corporation dated May 9, 1994
10.1.9(1) Agreement of Consolidation, Modification and Restatement of Notes
($165,000,000), dated as of May 1, 1994, between the Partnership
and the Funding Corporation, together with Endorsement from the
Funding Corporation dated May 9, 1994
10.2 Power Purchase Agreements
10.2.1(1) Power Purchase Agreement, dated as of December 7, 1987, between
JMC Selkirk and Niagara Mohawk Power Corporation ("Niagara
Mohawk")
10.2.2(1) Amendment to Power Purchase Agreement, dated as of December 14,
1989, between JMC Selkirk and Niagara Mohawk
10.2.3(1) Second Amendment to Power Purchase Agreement, dated as of
January, 25, 1990, between JMC Selkirk and Niagara Mohawk
40
10.2.4(1) Third Amendment to Power Purchase Agreement, dated as of October
23, 1992 between JMC Selkirk and Niagara Mohawk
10.2.5(3) Fourth Amendment to Power Purchase Agreement, dated as of June
26, 1996 between the Partnership and Niagara Mohawk
10.2.6(8) Amended and Restated Power Purchase Agreement dated as of July 1,
1998 between the Partnership and Niagara Mohawk
10.2.7(9) Mutual General Release and Agreement dated as of July 1, 1998
between the Partnership and Niagara Mohawk
10.2.8(1) Agreement dated as of March 31, 1994, between the Partnership and
Niagara Mohawk
10.2.9(5) Letter Agreement dated as of April 18, 1997, between the
Partnership and Niagara Mohawk
10.2.10(1) Termination of the Subordination Agreement and the Assignment of
Contracts and Security Agreement, as amended, dated May 9, 1994,
among Niagara Mohawk, Chase, as Agent, and the Partnership
10.2.11(1) License Agreement between the Partnership and Niagara Mohawk,
dated as of October 23, 1992
10.2.12(1) Power Purchase Agreement, dated as of April 14, 1989, between Con
Edison Company of New York, Inc. ("Con Edison") and JMC Selkirk
10.2.13(1) Rider to Power Purchase Agreement, dated as of September 13,
1989, between Con Edison and JMC Selkirk
10.2.14(1) First Amendment to Power Purchase Agreement, dated as of
September 13, 1991, between Con Edison and JMC Selkirk
10.2.15(1) Letter Agreement Regarding Extending the Term of the Power
Purchase Agreement, dated as of May 28, 1992, between Con Edison
and JMC Selkirk
10.2.16(1) Second Amendment to Power Purchase Agreement, dated as of October
22, 1992, between Con Edison and JMC Selkirk
10.2.17(4) Third Amendment to Power Purchase Agreement, dated as of
September 13, 1996, between Con Edison and the Partnership
41
10.2.18(1) Letter Agreement Regarding Arbitration, dated October 22, 1992,
between Con Edison and JMC Selkirk
10.2.19(1) Letter Agreement Regarding Sale of Capacity above 265 MW, dated
as of October 22, 1992, between Con Edison and JMC Selkirk
10.2.20(1) Notice, Certificate and Waiver of Con Edison for assignment by
Selkirk Cogen Partners, L.P. ("SCP II") to the Partnership
pursuant to the merger, dated October 19, 1992
10.2.21(1) Letter Agreement regarding Alternative Fuel Supply, dated as of
July 29, 1994, between Con Edison and the Partnership
10.3 Construction Agreements
10.3.1(1) Engineering, Procurement and Construction Services Agreement,
dated as of October 21, 1992, between the Partnership and Bechtel
Construction of Nevada and Bechtel Associates Professional
Corporation (the "Contractor")
10.4 Steam Agreements
10.4.1(1) Agreement for the Sale of Steam, dated as of October 21, 1992,
between the Partnership and General Electric Company ("General
Electric")
10.4.2(1) Amendment to Steam Sales Agreement, dated as of August 12, 1993,
between the Partnership and General Electric
10.4.3(1) Amended and Restated Operation and Maintenance Agreement, dated
as of October 22, 1992, between the Partnership and General
Electric
10.4.4(1) Second Amendment to Steam Sales Agreement, dated December 7,
1994, between the Partnership and General Electric
10.4.5(2) Third Amendment to Steam Sales Agreement, dated May 31, 1995,
between the Partnership and General Electric
10.5 Fuel Supply Contracts
10.5.1(1) Amended and Restated Gas Purchase Contract, dated as of September
26, 1992, between Paramount Resources Ltd. ("Paramount") and the
Partnership
42
10.5.2(1) First Amendment to the Amended and Restated Gas Purchase
Contract, dated as of October 5, 1992, between Paramount and the
Partnership
10.5.3(1) Second Amendment to the Amended and Restated Gas Purchase
Contract, dated as of December 1, 1993, between Paramount and the
Partnership
10.5.4(10) Second Amended and Restated Gas Purchase Contract, dated as of
May 6, 1998, between the Partnership and Paramount
10.5.5(1) Letter Agreement, dated as of October 25, 1993, between the
Partnership and Paramount
10.5.6(1) Indemnity Agreement, dated as of February 20, 1989, by the
Partnership in favor of Paramount
10.5.7(1) Letter Agreement, dated as of June 11, 1990, between the
Partnership and Paramount
10.5.8(1) Indemnity Amending and Supplemental Agreement, dated as of June
19, 1990, between the Partnership and Paramount
10.5.9(1) Intercreditor Agreement, dated as of October 21, 1992, between
Paramount, the Partnership and Chase, as Agent
10.5.10(1) Specific Assignment of Unit 1 TransCanada Transportation
Contract, dated as of December 20, 1991, by the Partnership to
Paramount
10.5.11(1) Amendment No. 1 to Specific Assignment, dated as of October 21,
1992, between the Partnership and Paramount
10.5.12(1) Amended and Restated Gas Purchase Agreement, dated as of January
21, 1993, between the Partnership and Atcor Ltd. ("Atcor")
10.5.13(1) Amended and Restated Gas Purchase Agreement, dated as of October
22, 1992, between the Partnership, as assignee, and Imperial Oil
Resources ("Imperial")
10.5.14(1) Amended and Restated Gas Purchase Agreement, dated as of October
22, 1992, between the Partnership, as assignee, and PanCanadian
Pertroleum Limited ("PanCanadian")
10.5.15(1) Back-up Fuel Supply Agreement, dated as of June 18, 1992, between
Phibro Energy USA, Inc. ("Phibro") and SCP II
43
10.6 Fuel Transportation Agreements
10.6.1(1) Gas Transportation Contract for Firm Reserved Service, dated as
of February 7, 1991, between Iroquois Gas Transmission System,
L.P. ("Iroquois") and the Partnership
10.6.2(1) Letter Agreement, dated June 30, 1993, from Iroquois and
acknowledged and accepted for the Partnership by JMC Selkirk
10.6.3(1) Firm Service Contract for Firm Transportation Service, dated as
of September 6, 1991, between TransCanada PipeLines Limited
("TransCanada") and the Partnership
10.6.4(1) Amending Agreement, dated as of May 28, 1993, between the
Partnership and TransCanada
10.6.5(11) Amending Agreement, dated as of July 20, 1998, between the
Partnership and TransCanada
10.6.6(1) Firm Natural Gas Transportation Agreement, dated as of April 18,
1991, between Tennessee Gas Pipeline and the Partnership
10.6.7(1) Clarification Letter from Tennessee, dated April 18, 1991,
between the Partnership and Tennessee
10.6.8(1) Supplemental Agreement (Unit 1), dated April 18, 1991, between
the Partnership and Tennessee
10.6.9(1) Operational Balancing Agreement, dated as of September 1, 1993,
between the Partnership and Tennessee
10.6.10(1) Interruptible Transportation Agreement, dated as of September 1,
1993, between the Partnership and Tennessee
10.6.11(1) License Agreement for the Ten-Speed 2 System, dated as of July
21, 1993, between the Partnership, Tennessee, Midwestern Gas
Transmission Company and East Tennessee Natural Gas Company
10.6.12(1) Firm Service Contract for Firm Transportation Service, dated as
of March 16, 1994, between the Partnership and TransCanada
10.6.13(1) Letter Agreement, dated as of March 24, 1994, between the
Partnership and TransCanada
44
10.6.14(1) Gas Transportation Contract for Firm Reserved Service, dated as
of April 5, 1994, between the Partnership and Iroquois
10.6.15(1) Letter Agreement, dated as of March 31, 1994, between the
Partnership and Iroquois
10.6.16(1) Firm Natural Gas Transportation Agreement, dated as of April 11,
1994, between the Partnership and Tennessee
10.6.17(1) Tennessee Supplemental Agreement (Unit 2), dated as of October
21, 1992, between Tennessee and the Partnership
10.6.18(1) Letter Agreement, dated September 22, 1993, between the
Partnership and Tennessee
10.6.19(2) Consent and Agreement, dated May 15, 1995, between the
Partnership, Iroquois and the Trustee
10.7 Transmission and Interconnection Agreements
10.7.1(1) Transmission Services Agreement, dated as of December 13, 1990,
between Niagara Mohawk and SCP II
10.7.2(1) Notice, Certificate, Agreement, Waiver and Acknowledgment to
Niagara Mohawk of Assignment of Transmission Agreement to the
Partnership, dated as of October 23, 1992
10.7.3(1) Interconnection Agreement (Unit 1), dated as of October 20, 1992,
between Niagara Mohawk and SCP II
10.7.4(1) Interconnection Agreement (Unit 2), dated as of October 20, 1992,
between Niagara Mohawk and SCP II
10.8 Administrative Services Agreements and Water Supply Agreement
10.8.1(1) Project Administrative Services Agreement, dated as of June 15,
1992, between JMCS I Management, Inc. ("JMCS I Management") and
the Partnership
10.8.2(1) First Amendment to Project Administrative Services Agreement,
dated as of October 23, 1992, between JMCS I Management and the
Partnership
45
10.8.3(1) Second Amendment to Project Administrative Services Agreement,
dated as of May 1, 1994, between JMCS I Management and the
Partnership
10.8.4(1) Water Supply Agreement, dated as of May 6, 1992, between the Town
of Bethlehem, New York and the Partnership
10.9 Real Estate Documents
10.9.1(1) Second Amended and Restated Lease Agreement, dated as of October
21, 1992, between the Partnership and General Electric
10.9.2(1) Amended and Restated First Amendment to Second Amended and
Restated Lease Agreement, dated as of April 30, 1994, between the
Partnership and General Electric
10.9.3(1) Unit 2 Grant of Easement, dated as of October 21, 1992, made by
General Electric in favor of the Partnership (regarding Unit 2
Substation and Transmission Line)
10.9.4(1) Declaration of Restrictive Covenants by General Electric, dated
as of October 21, 1992 (regarding Wetlands Remediation Areas)
10.9.5(1) Utilities Building Lease Agreement, dated as of October 21, 1992,
between General Electric, as Landlord, and the Partnership, as
Tenant
10.9.6(1) Easement Agreement, dated as of May 27, 1992, between Charles
Waldenmaier and the Partnership, as assignee
10.9.7(1) Facility Lease Agreement, dated as of October 21, 1992, between
the Partnership, as Landlord, and the Town of Bethlehem, New York
Industrial Development Agency ("IDA"), as Tenant
10.9.8(1) Amended and Restated First Amendment to Facility Lease Agreement,
dated as of April 30, 1994, between the Partnership and the IDA
10.9.9(1) Sublease Agreement, dated as of October 21, 1992, between the
Partnership, as Subtenant, and the IDA, as Sublandlord
10.9.10(1) Amended and Restated First Amendment to Sublease Agreement, dated
as of April 30, 1994, between the Partnership and the IDA
10.9.11(1) Payment in Lieu of Taxes Agreement, dated as of October 21, 1992,
between the Partnership and the IDA
46
10.10 Security Documents
10.10.1(1) Assignment of Agreements, dated as of May 1, 1994, among Yasuda
Bank and Trust Company (U.S.A.) ("Yasuda"), Dresdner Bank AG, New
York and Grand Cayman Branches ("Dresdner"), the Depositary
Agent, the Collateral Agent, the Partnership and the Funding
Corporation
10.10.2(1) Depositary Agreement, dated as of May 1, 1994, among the Funding
Corporation, the Partnership, Bankers Trust Company as collateral
agent ("Collateral Agent") and Bankers Trust Company, as
depositary agent (the "Depositary Agent")
10.10.3(1) Equity Contribution Agreement, dated as of May 1, 1994, among the
Partnership, Cogen LP, Cogen GP, Makowski Selkirk and Chase
10.10.4(1) Cash Collateral Agreement, dated as of May 1, 1994, among
Makowski Selkirk, the Partnership and Chase, as Agent
10.10.5(1) Cash Collateral Agreement, dated as of May 1, 1994, among Cogen
LP, the Partnership and Chase, as Agent
10.10.6(1) Cash Collateral Agreement, dated as of May 1, 1994, among Cogen
GP, the Partnership and Chase, as Agent
10.10.7(1) Agreement of Spreader, Consolidation and Modification of
Leasehold Mortgages, Security Agreements and Fixture Financing
Statements, (the "First Consolidated Mortgage"), dated as of May
1, 1994, in the principal amount of $227,000,000 among the
Partnership, the IDA and the Collateral Agent
10.10.8(1) Agreement of Spreader, Consolidation and Modification of
Leasehold Mortgages, Security Agreements and Fixture Financing
Statements, dated as of May 1, 1994, in the principal amount of
$122,000,000 among the Partnership, the IDA and the Collateral
Agent
10.10.9(1) Agreement of Spreader and Modification of Leasehold Mortgage (the
"Restated Mortgage"), dated as of May 1, 1994, in the principal
amount of $43,000,000 among the Partnership, the IDA and the
Collateral Agent
10.10.10(1) Agreement of Modification and Severance of Mortgage (the
"Mortgage Splitter Agreement"), dated as of May 1, 1994, among
the Partnership, the IDA and the Collateral Agent
47
10.10.11(1) Leasehold Mortgage (Substitute Mortgage No. 1), dated as of May
1, 1994, in the principal amount of $9,099,000 given by the
Partnership and the IDA to the Collateral Agent
10.10.12(1) Leasehold Mortgage (Substitute Mortgage No. 2), dated as of May
1, 1994, in the principal amount of $43,000,000 given by the
Partnership and the IDA to the Collateral Agent
10.10.13(1) Leasehold Mortgage (Substitute Mortgage No. 1), dated as of May
1, 1994, in the principal sum of $16,601,000 given by the
Partnership and the IDA to the Collateral Agent
10.10.14(1) Leasehold Mortgage (Gap Mortgage No. 2) in the principal amount
of $42,199,000, dated as of May 1, 1994, given by the Partnership
and the IDA to the Collateral Agent
10.10.15(1) Leasehold Mortgage, Security Agreement and Fixture Financing
Statement (the "Chase Mortgage"), dated as of May 1, 1994, given
by the Partnership and the IDA to the Collateral Agent
10.10.16(1) Amended and Restated Security Agreement and Assignment of
Contracts (the "Security Agreement"), dated as of May 1,1994,
made by the Partnership in favor of the Collateral Agent
10.10.17(1) Pledge and Security Agreement (the "Partnership Pledge
Agreement"), dated as of May 1, 1994, from the Partnership in
favor of the Collateral Agent
10.10.18(1) Security Agreement (the "Company Security Agreement"), dated as
of May 1, 194, from the Company in favor of the Collateral Agent
10.10.19(1) Intercreditor Agreement, dated as of May 1, 1994, among the
Trustee, the Credit Bank, the Funding Corporation, the
Partnership, the Collateral Agent and certain other parties
10.10.20(1) Purchase Agreement and Transfer Supplement, dated as of May 1,
1994, among Chase, Dresdner, Yasuda, the Funding Corporation and
the Partnership
10.11 Other Material Project Contracts
10.11.1(1) Purchase Agreement, dated April 29, 1994, among the Funding
Corporation, the Partnership, CS First Boston Corporation, Chase
Securities, Inc. and Morgan Stanley & Co. Incorporated
48
10.11.2(1) Capital Contribution Agreement, dated as of April 28, 1994, among
the Partnership, JMC Selkirk, JMCS I Investors, Cogen
Technologies GP and Cogen Technologies LP (collectively, the
"Partners")
10.11.3(1) Equity Depositary Agreement, dated as of May 1, 1994, among the
Partnership, the Partners, Makowski Selkirk and Citibank, N.A. as
Special Agent
10.11.4(7) Master Restructuring Agreement, dated as of July 9, 1997, among
Niagara Mohawk, the Partnership and other Independent Power
Producers (defined therein)
16(16) Letter from former accountant (Arthur Andersen, LLP), dated as of
March 9, 1999, to the Securities and Exchange Commission
regarding the Partnership's change in certifying accountant.
21(1) Subsidiaries of the Funding Corporation and Partnership
27 Financial Data Schedule (for electronic filing purposes only)
99 Additional Exhibits
99.1(12) Officer's Certificate of the Partnership., dated August 31, 1998,
delivered to Bankers Trust Company, as Trustee
99.2(13) Independent Engineer's Certificate of R.W. Beck, Inc., dated as
of August 31, 1998, delivered to Bankers Trust Company, as
Trustee
99.3(14) Gas Consultant's Certificate of C.C. Pace Consulting, LLC, dated
August 28, 1998, delivered to Bankers Trust Company, as Trustee
99.4(15) Press Release of the Partnership, dated August 31, 1998
- -------------------------------------------
(1) Incorporated herein by reference to the Registrant's Registration Statement
on Form S-1 filed September 1, 1994, as amended (File No. 33-83618).
(2) Incorporated herein by reference to the Registrant's Quarterly Report on
Form 10-Q for the Quarterly Period Ended June 30, 1995 filed August 14,
1995.
(3) Incorporated herein by reference to the Registrant's Quarterly Report on
Form 10-Q for the Quarterly Period Ended June 30, 1996 filed August 13,
1996.
49
(4) Incorporated herein by reference to the Registrant's Quarterly Report on
Form 10-Q for the Quarterly Period Ended September 30, 1996 filed November
14, 1996.
(5) Incorporated herein by reference to the Registrant's Quarterly Report on
Form 10-Q for the Quarterly Period Ended March 31, 1997 filed May 15, 1997.
(6) Incorporated herein by reference to the Registrant's Quarterly Report on
Form 10-Q for the Quarterly Period Ended June 30, 1997 filed August 14,
1997.
(7) Incorporated herein by reference to Exhibit Number 10.28 of the Current
Report on Form 8-K of Niagara Mohawk Power Corporation filed July 10, 1997.
(8) Incorporated herein by reference to Exhibit Number 10.1 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(9) Incorporated herein by reference to Exhibit Number 10.2 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(10) Incorporated herein by reference to Exhibit Number 10.3 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(11) Incorporated herein by reference to Exhibit Number 10.4 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(12) Incorporated herein by reference to Exhibit Number 99.1 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(13) Incorporated herein by reference to Exhibit Number 99.2 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(14) Incorporated herein by reference to Exhibit Number 99.3 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(15) Incorporated herein by reference to Exhibit Number 99.4 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(16) Incorporated herein by reference to Exhibit Number 16 of the Registrant's
Current Report on Form 8-K filed March 9, 1999.
50
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: March 31, 1999 /s/ JMC SELKIRK, INC.
---------------------------------
General Partner
Date: March 31, 1999 /s/ JOHN R. COOPER
----------------------------------
Name: John R. Cooper
Title: Senior Vice President and
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed by the following persons on behalf of the Registrant in
the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ P. CHRISMAN IRIBE President and Director March 31, 1999
- ----------------------
P. Chrisman Iribe
/s/ STEPHEN A. HERMAN Director March 31, 1999
- ----------------------
Stephen A. Herman
/s/ JOHN R. COOPER Senior Vice President and March 31, 1999
- ------------------- Chief Financial Officer
John R. Cooper
/s/ DOUGLAS F. EGAN Senior Vice President March 31, 1999
- --------------------
Douglas F. Egan
/s/ DAVID N. BASSETT Treasurer March 31, 1999
- ---------------------
David N. Bassett
51
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: March 31, 1999 /s/ JOHN R. COOPER
----------------------------------
Name: John R. Cooper
Title: Senior Vice President and
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed by the following persons on behalf of the Registrant in
the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ P. CHRISMAN IRIBE President and Director March 31, 1999
- ----------------------
P. Chrisman Iribe
/s/ STEPHEN A. HERMAN Director March 31, 1999
- ----------------------
Stephen A. Herman
/s/ JOHN R. COOPER Senior Vice President and March 31, 1999
- ------------------- Chief Financial Officer
John R. Cooper
/s/ DOUGLAS F. EGAN Senior Vice President March 31, 1999
- --------------------
Douglas F. Egan
/s/ DAVID N. BASSETT Treasurer March 31, 1999
- ---------------------
David N. Bassett
52