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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 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, 1997
Commission File Number 33-83618
SELKIRK COGEN PARTNERS,L.P.
(Exact name of Registrant (Guarantor) as specified in its charter)
Delaware 51-0324332
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
SELKIRK COGEN FUNDING CORPORATION
(Exact name of Registrant as specified in its charter)
Delaware 51-0354675
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
One Bowdoin Square, Boston, Massachusetts 02114
(Address of principal executive offices, including zip code)
(617) 227-8080
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
8.65% First Mortgage Bonds Due 2007, Series A
8.98% First Mortgage Bonds Due 2012, Series A
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 31, 1998, 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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This document consists of 66 pages of which this page is page 0.
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TABLE OF CONTENTS
Page
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PART I
Item 1. Business..................................................... 2
Item 2. Properties...................................................14
Item 3. Legal Proceedings............................................15
Item 4. Submission of Matters to a Vote of Security Holders..........16
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters..........................................17
Item 6. Selected Financial Data......................................17
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations..........................18
Item 8. Financial Statements and Supplementary Data..................26
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure..........................26
PART III
Item 10. Directors and Executive Officers of the Registrant...........27
Item 11. Executive Compensation.......................................28
Item 12. Security Ownership of Certain Beneficial Owners and
Management...................................................29
Item 13. Certain Relationships and Related Transactions...............30
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K..................................................31
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PART I
ITEM 1. BUSINESS
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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"). See "The Facility and Certain Project
Contracts, Niagara Mohawk" in this report for a discussion of certain
developments related to the restructuring of the Partnership's Niagara Mohawk
Power Purchase Agreement.
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) 227-8080.
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, L.P. ("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. 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.
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JMC Selkirk is an indirect, wholly-owned subsidiary of J. Makowski
Company, Inc. ("J. Makowski Company"), and JMCS I Management is a direct,
wholly-owned subsidiary of J. Makowski Company. J. Makowski Company owns
interests in gas-fired electric generating facilities and natural gas supply
and transportation projects. In August 1994, a controlling interest in J.
Makowski Company was acquired by a special purpose corporation jointly owned
by PG&E Generating Company, a subsidiary of PG&E Enterprises, and Bechtel
Generating Company, a subsidiary of Bechtel Enterprises, Inc. Investors is a
limited partnership of JMCS I Holdings, Inc., JMC Selkirk, Inc. (each an
affiliate of J. Makowski Company) and TPC Generating, Inc.
Cogen Technologies GP and Cogen Technologies LP are each affiliates of
Cogen Technologies, Inc. ("Cogen Technologies"). Cogen Technologies has
developed and owns an interest in an electric generating facility.
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"). GPUI
is actively engaged in the business of developing, owning and/or operating
domestic and foreign independent power generation projects.
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 8.9 8% 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").
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The Bonds, the Partnership Loans and the Guarantee are not guaranteed by,
or otherwise obligations of, the Partners, J. Makowski Company, TPC
Generating, Inc., PG&E Enterprises, Bechtel Enterprises, 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 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").
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Niagara Mohawk
On October 6, 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 (the "Commission") explaining the Power Choice proposal (the
"Power Choice Statement"). In the Power Choice Statement, Niagara Mohawk
describes 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"). On July 10, 1997, Niagara Mohawk
filed a Report on Form 8-K with the Commission stating that Niagara Mohawk
had entered into a Master Restructuring Agreement ("MRA") pursuant to which
it and the twenty-nine independent power producers which had signed the MRA
propose to terminate, restate or amend their respective power purchase
agreements. On October 17, 1997, Niagara Mohawk filed a Report on Form 8-K
with the Commission stating that on October 11, 1997, Niagara Mohawk filed
its Power Choice settlement with the NYPSC which incorporates the terms of
the MRA. On February 24, 1998, the NYPSC approved Niagara Mohawk's Power
Choice settlement proposal, which includes the implementation of the MRA.
The consideration for the independent power purchasers' agreement varies
by party, and may consist of cash, short term notes, shares of Niagara
Mohawk's Common Stock or certain swap contracts. Among the contracts which
is proposed to be restructured is the Niagara Mohawk Power Purchase Agreement
for the electric output of Unit 1. Pursuant to the MRA and subject to
implementation as described below, the parties propose to restructure the
Niagara Mohawk Power Purchase Agreement to provide for the sale of
electricity by the Partnership pursuant to a pre-determined schedule of
output at a price based on certain indices for a period of 10 years in lieu
of the delivery and price provisions of the Niagara Mohawk Power Purchase
Agreement as currently in effect. The Partnership anticipates that, if and
when a restructured power purchase agreement goes into effect, Niagara Mohawk
will relinquish its right to direct dispatch of Unit 1, the electrical output
of Unit 1 will be sold to Niagara Mohawk and other purchasers based on market
conditions then in effect, and the Partnership will receive certain fixed
payments from Niagara Mohawk under the restructured power purchase agreement
and other payments under the MRA.
The details of the physical delivery and pricing arrangements are subject
to final agreement with Niagara Mohawk, and possible modifications to other
Partnership contracts for Unit 1 continue to be the subject of extensive
negotiations. Implementation of the MRA is subject to a number of
significant conditions, including without limitation Niagara Mohawk and the
Partnership negotiating the restructured Unit 1 Power Purchase Agreement, the
receipt of all regulatory approvals, the receipt of all consents by third
parties necessary for the transaction contemplated by the MRA (including
satisfying certain standards under the Partnership's Trust Indenture relating
to the absence of material adverse changes or receiving any required approval
of bondholders or other creditors), the Partnership's entering into new third
party arrangements which will enable the Partnership to restructure its
project on a reasonably satisfactory economic basis, and the receipt by
Niagara Mohawk and the Partnership of all necessary approvals from their
respective boards of directors, shareholders and partners. Should Niagara
Mohawk and the Partnership satisfy all of the conditions to effectuating the
transactions contemplated by the MRA with respect to the Partnership, Niagara
Mohawk may nevertheless terminate the MRA if Niagara Mohawk determines that,
as a result of the failure to satisfy the conditions of the MRA by other
independent power producers, the benefits anticipated to be received by
Niagara Mohawk pursuant to the MRA have been materially and adversely
affected. Further, final implementation of the MRA is conditioned upon
Niagara Mohawk's successful completion of financing required to fund certain
of its payment obligations under agreements to implement the MRA.
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The Partnership, as a party to the MRA, is committed to negotiate with
Niagara Mohawk and other parties to reach agreement on contractual
arrangements required to restructure the Niagara Mohawk Power Purchase
Agreement pursuant to the MRA; however, the Partnership expresses no opinion
with respect to the likelihood that all of the conditions to implementation
of the MRA will be met. Further, the Partnership expresses no opinion with
respect to the viability of Niagara Mohawk's proposed alternatives should the
implementation of the MRA not be completed, such as Niagara Mohawk's proposal
in the context of the Power Choice Statement to take possession of
independent power projects through the power of eminent domain and to
thereafter sell such projects or Niagara Mohawk's position that it has not
ruled out the ultimate possibility of a filing for restructuring under
Chapter 11 of the U.S. Bankruptcy Code as set forth in the Power Choice
Statement. Nevertheless, in the absence of agreement on a definitive
restructured power purchase agreement, the Partnership continues to believe
that the Niagara Mohawk Power Purchase Agreement is a valid and binding
contract with Niagara Mohawk. Given the uncertainties with respect to such
implementation, the Partnership is unable to determine what effect, if any,
the restructured power purchase agreement or the Power Choice proposal will
have on the Partnership, its business or net operating revenues. For the
year ended December 31, 1997, electric sales to Niagara Mohawk accounted for
approximately 19.3% of total project revenues.
Previously, in connection with Niagara Mohawk's March 10, 1997
announcement of the agreement in principle, Standard & Poor's placed the
Bonds on creditwatch "with negative implications," based in part on its
analysis of the current reports on Form 8-K filed in March 1997 by Niagara
Mohawk and the Partnership, respectively, and its belief that the
restructuring has the potential to erode cash flow coverage derived from
long-term contracts supporting the Bonds. To date Standard & Poor's has not
changed their outlook on the Bonds. Additionally, as of the date of this
report, Moody's Investors Service has not changed its rating or its previous
"negative outlook" on the Bonds as a result of the developments.
6
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Unit 1 commenced commercial operation on April 17, 1992 and is selling at
least 79.9 MW of electric capacity and associated energy to Niagara Mohawk
under the current long-term contract that allows Niagara Mohawk to schedule
Unit 1 for dispatch on an economic basis (the "Niagara Mohawk Power Purchase
Agreement"). The term of the Niagara Mohawk Power Purchase Agreement is 20
years from the date of initial commercial operation of Unit 1. The Niagara
Mohawk Power Purchase Agreement provides for four payment components: (i) a
capacity payment, (ii) an energy payment, (iii) a transportation payment and
(iv) an operation and maintenance ("O&M") payment. The capacity payment and
portions of the transportation and O&M payments are fixed charges to be paid
whether or not Unit 1 is dispatched on-line, subject, in the case of the
capacity payment, to certain discounts and rebates in accordance with the
Niagara Mohawk Power Purchase Agreement. The energy payment and portions of
the transportation and O&M payments are variable charges based on electricity
produced by Unit 1 and delivered to Niagara Mohawk. Pursuant to an agreement
which, in part, amends and supplements the Niagara Mohawk Power Purchase
Agreement, the Partnership and Niagara Mohawk have agreed that the 10%
reduction in the Partnership's rates which would otherwise be triggered under
the Niagara Mohawk Power Purchase Agreement as a result of Unit 1's exceeding
the 80 MW output limitation imposed on a New York State co-generation
facility will not apply to the Partnership, subject to the receipt of any
regulatory approvals or the adoption of any legislation that may be required.
Niagara Mohawk and the Partnership have subsequently confirmed that no
additional regulatory approvals or legislation is necessary, and have agreed
that Unit 1 may exceed the 80 MW limit during specific transactions
authorized by Niagara Mohawk. As of the date of this report, the Partnership
has sold output in excess of 80 MW from Unit 1 only to Niagara Mohawk.
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 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 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. The Partnership does
not expect a restructuring of the Niagara Mohawk Power Purchase Agreement to
have any effect on Unit 2 transmission services provided by Niagara Mohawk.
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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 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 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 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, 1997 electric sales to Con Edison accounted for approximately
72.5% of total project revenues.
Con Edison by a letter dated September 19, 1994 claimed the right to
acquire that portion of Unit 2's firm natural gas supply not used in
operating Unit 2, when Unit 2 is dispatched off-line or at less than full
capability. The Con Edison Power Purchase Agreement contains no express
language granting Con Edison any rights with respect to such excess natural
gas. Nevertheless, Con Edison has argued that, since payments under the
contract include fixed fuel charges which are payable whether or not Unit 2
is dispatched on-line, Con Edison is entitled to take delivery of any excess
natural gas. The Partnership vigorously disputes the position adopted by Con
Edison, based notably on the absence of any contractual provision according
Con Edison the claimed rights but also on the fact that the Partnership has
assumed the risk under the Con Edison Power Purchase Agreement that the fuel
charges payable by Con Edison are insufficient to cover the costs actually
incurred by the Partnership. By a letter dated May 23, 1995, Con Edison
indicated its intention to pursue the claim asserted in the September 19,
1994 letter. In the May 23, 1995 letter, Con Edison reserved the right to
claim 100% of the margins derived from the sales of Unit 2's firm natural gas
supply not used in operating Unit 2 (non-plant gas sales) and requested that
the Partnership reduce the monthly amount invoiced to Con Edison by 50% of a
calculated value of the non-plant gas sales. The Partnership strenuously
objected to Con Edison's contentions and, at a meeting between the
Partnership and Con Edison, Con Edison agreed to continue not to deduct any
amount attributable to non-plant gas sales from payments made upon monthly
invoices but stated it would do so under protest, pending further discussions
between the parties. Since the commencement of commercial operations of Unit
2, the Partnership made and continues to make, from time to time, excess gas
lay-off sales from Unit 2's gas supply. The Partnership does not intend to
adjust the monthly invoices issued to Con Edison and continues to assert that
Con Edison is not entitled to any revenues or margins derived from non-plant
gas sales. In the event Con Edison were to pursue its asserted claim, the
Partnership would expect to pursue all available legal remedies, but there
can be no certainty that the outcome of such remedial action would be
favorable to the Partnership or, if favorable, would provide for the
Partnership's full recovery of its damages.
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.
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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.
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 will reduce 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, 1997 steam sales to General Electric accounted
for approximately 0.3% of total project revenues. 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
in to 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 "Paramount Contract"). The Paramount Contract requires Paramount to
maintain a level of recoverable reserves and deliverability from its
dedicated reserves through the term of the 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,
Iroquois Gas Transmissions System, L.P. and Tennessee Gas Pipeline Company.
Each of the Unit 1 Gas Transportation Contracts has a term of 20 years
beginning November 1, 1992. Either the Partnership (at Niagara Mohawk's
direction or on its own initiative) or Paramount may require renegotiation,
not more frequently than annually, of the commodity charge and/or method of
escalation and, failing agreement (including Niagara Mohawk's concurrence),
these pricing issues may be submitted to arbitration binding on the
Partnership, Paramount and Niagara Mohawk. The Paramount Contract
establishes an arbitration and renegotiation procedure which coordinates with
the Niagara Mohawk Power Purchase Agreement. The Partnership is currently
engaged in negotiations with Paramount regarding modifications to the volume,
pricing and other provisions of the Paramount Contract that may be required
in conjunction with any restructuring of the Niagara Mohawk Power Purchase
Agreement. The Partnership is also considering alternative arrangements for
Unit 1's natural gas supply in the event that the restructuring of the
Niagara Mohawk Power Purchase Agreement is implemented.
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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 Pipelines Limited, Iroquois Gas Transmissions System,
L.P. and Tennessee Gas Pipeline Company. 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 the scheduled deliveries of
electricity to Niagara Mohawk and Con Edison. 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 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.
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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.
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 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 long-term contracts to sell
electric generating capacity and energy from the Facility to Niagara Mohawk
and Con Edison; therefore, subject to the effect of any restructured Niagara
Mohawk Power Purchase Agreement, it does not expect competitive forces to
have a significant effect on its business. Nevertheless, each of these Power
Purchase Agreements permits the purchasing utility to schedule the Unit for
dispatch 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 purchasing utility from other sources.
Accordingly, competitive forces may have some effect on the Facility's
dispatch levels. Furthermore, if and when the restructured Niagara Mohawk
Power Purchase Agreement goes into effect, the Partnership would anticipate
marketing, under certain conditions, the electric output of Unit 1 to
purchasers other than Niagara Mohawk based on market conditions then in
effect. 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.
11
<PAGE>
Seasonality
The Partnership's reliance on its power producer's customer 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.
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.
12
<PAGE>
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 (i.e., the net electrical output of Unit 1's gas
turbine and steam turbine must be dedicated to the Niagara Mohawk Power
Purchase Agreement and the net electrical output of Unit 2's turbines and
steam turbine must be dedicated to the Con Edison Power Purchase Agreement).
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 th e 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 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.
13
<PAGE>
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 of 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 of 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. Although mutual consensus regarding
the administrative revisions to, and format of, the Facility's FRP is
anticipated, the Partnership cannot determine what, if any, actions could
potentially be taken by the EPA.
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 and Bethesda
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") 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.
14
<PAGE>
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 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. Currently pending
proceedings primarily relate to filings made by Iroquois Gas Transmission
System, L.P ("IGTS"), in which IGTS is seeking rate adjustments and authority
to collect additional costs for gas transportation services, and certain
proceedings involving, Tennessee Gas Pipeline Company ("Tennessee"), in which
Tennessee is seeking changes to its operating terms and conditions, and rate
adjustments. In 1996, the Partnership entered into a settlement with
Tennessee, subject to FERC approval, that will resolve a substantial number
of these Tennessee-related proceedings. During the first quarter 1997, the
FERC approved the settlement.
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 NYPSC reopened the curta
ilment 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. The
Partnership expects that any agreement which it enters into with Niagara
Mohawk to implement the MRA will waive Niagara Mohawk's right, if any, to
curtail purchases from the Partnership. See Part I Item 1. Business - The
Facility and Certain Project Contracts - Niagara Mohawk for discussion of the
MRA.
15
<PAGE>
In any event, 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 Niagara Mohawk and Con Edison some measure of
generic curtailment rights. The Partnership's position is based in part on
the fact that neither Niagara Mohawk nor Con Edison bargained for an express
curtailment right in its Power Purchase Agreement and the Partnership agreed
to permit Niagara Mohawk and Con Edison to direct the dispatch of the
relevant Unit. Nevertheless, both Niagara Mohawk and Con Edison have refused
to expressly waive their claimed curtailment rights against dispatchable
facilities and have not agreed to exempt the Facility from curtailment,
notwithstanding the absence of contractual language in the Power Purchase
Agreements granting the utilities this right. If Niagara Mohawk and Con
Edison were to receive NYPSC authorization to curtail power purchases from
Qualifying Facilities including dispatchable facilities, they 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.
16
<PAGE>
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 of the Partnership is held by the Partners and, therefore,
there is no established public market for the Partnership's common equity.
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 Nine Months Ended
December 31, December 31,
------------------------------- -----------------
1997 1996 1995 1994 1994
---- ---- ---- ---- ----
(in thousands)
Statement of Operations
Data:
Operating revenues $171,583 $174,442 $155,778 $ 72,707 $ 61,450
Cost of revenues 121,305 119,747 114,491 52,331 44,238
Other operating
expenses 6,584 6,669 7,174 5,009 4,090
Operating income 43,694 48,026 34,113 15,367 13,122
Net interest
expense 32,234 32,844 32,392 17,094 14,621
Write-off of
deferred finance
charges and interest
rate hedge --- --- --- 34,885 34,885
-------- -------- -------- -------- --------
Net income (loss) $ 11,460 $ 15,182 $ 1,721 $(36,612) $(36,384)
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
December 31, March 31,
------------------------------------ ------------
1997 1996 1995 1994 1994
---- ---- ---- ---- ----
(in thousands)
Balance Sheet Data:
Plant and equipment
(net) $321,537 $334,229 $346,285 $354,440 $ 90,083
Construction
work-in-progress --- --- --- --- 225,171
Total assets 385,874 401,454 416,080 441,555 347,757
Long-term debt and
bonds 385,955 389,253 391,420 392,000 332,929
Partners' capital (32,282) (18,810) 1,530 20,821 360
17
<PAGE>
Supplementary Financial Information
The following is a summary of the quarterly results of operations for the
years ended December 31, 1995, December 31, 1996 and December 31, 1997
Three Months Ended (unaudited)
--------------------------------------------------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
(in thousands)
Year Ended
December 31, 1995
- --------------------
Operating revenues $ 39,130 $ 39,437 $ 37,349 $ 39,862
Gross profit 10,640 9,771 9,626 11,250
Net income 523 (168) 7 1,359
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
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
$11.5 million in 1997 and released for distribution to the partners
approximately $24.9 million.
Results of Operations
Year Ended December 31, 1997 Compared to the Year Ended December 31, 1996
The Partnership earned net income of $11.5 million for the year ended
December 31, 1997 as compared to net income of $15.2 million for the prior
year. The decrease in net income is primarily due to a decrease in gas
resale revenues which was primarily due to increased 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.
18
<PAGE>
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
------- ----- -------- -------- ------- ----- -------- --------
Niagara
Mohawk 33.1 403.9 57.23% 62.61% 29.9 303.1 44.81% 54.50%
Con
Edison 124.4 1,884.8 81.18% 89.89% 117.2 1,622.7 69.71% 87.61%
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 by each Units power purchaser (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 Niagara Mohawk increased approximately $3.2 million for the
year ended December 31, 1997 as compared to the prior year. Revenues for the
year ended December 31, 1997 were favorably impacted by increased energy
deliveries to Niagara Mohawk, as evidenced by the 1200 basis point increase
in the capacity factor from December 31, 1996 to December 31, 1997. For the
twelve months ended December 31, 1997, Niagara Mohawk dispatched the Unit
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 rates less
than full contract rates. For the twelve months ended December 31, 1996,
Niagara Mohawk dispatched the Unit 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 Con Edison increased $7.2 million for the year ended
December 31, 1997 as compared to the prior year. The increase in revenues
from Con Edison for the twelve months ended December 31, 1997 was primarily
due to an increase in delivered energy as evidenced by the 1100 basis point
increase in the capacity factor from December 31, 1996 to December 31, 1997.
19
<PAGE>
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 has implemented an energy efficiency
project in 1997 that will reduce 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 were approximately $0.4 million on
1,462.621 million pounds of steam delivered as compared to approximately $2.7
million on 1,867.330 million pounds of steam delivered for the prior year.
Revenue per unit of steam decreased during the year ended December 31, 1997
as compared to the prior year due to a decrease in steam demand as a result
of the energy efficiency project implemented by General Electric. Steam
revenues for the year ended December 31, 1997 includes an annual true-up of
approximately $0.7 million in favor of the steam host as compared to
approximately $0.2 million for the prior year.
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 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 to higher index fuel prices and rate
increases under the firm transportation contracts. The 0.3 million MMBtu
decrease for the year ended December 31, 1996 as compared to the prior year
is primarily due to a reduction in firm fuel purchases from suppliers.
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 for the year ended December
31, 1997 was comparable to the prior year. Deferred financing charges are
amortized using the effective interest method.
20
<PAGE>
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
attributable to approximately a $0.4 million increase in interest income for
the year ended December 31, 1997 as compared to the prior year.
Year Ended December 31, 1996 Compared to the Year Ended December 31, 1995
The Partnership earned net income of $15.2 million for the year ended
December 31, 1996 as compared to net income of $1.7 million for the prior
year. The increase in net income is primarily due to the increase in
electric and gas resale revenues which was primarily due to increased
dispatch and capacity of Unit 1, higher contract energy rates due to higher
fuel index prices for Unit 2 and an increase in average natural gas resale
prices.
Total revenues for the year ended December 31, 1996 were approximately
$174.4 million as compared to approximately $155.8 million for the prior
year.
Electric Revenues (dollars and kWh's in millions):
For the Year Ended
December 31, 1996 December 31, 1995
---------------------------------- --------------------------------
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ----- -------- --------
Niagara
Mohawk 29.9 303.1 44.81% 54.50% 27.5 293.6 41.95% 44.13%
Con
Edison 117.2 1,622.7 69.71% 87.61% 110.1 1,781.1 76.69% 85.42%
Revenues from Niagara Mohawk increased $2.4 million for the year ended
December 31, 1996 as compared to the prior year. Energy delivered to Niagara
Mohawk was sold primarily at full contract rates for the year ended December
31, 1996, whereas energy delivered to Niagara Mohawk during the twelve months
ended December 31, 1995 was primarily sold under special dispatch
arrangements. During 1995, the Partnership frequently entered into special
dispatch arrangements with Niagara Mohawk, at times when the Unit would have
otherwise been dispatched off-line, which called for the pricing of delivered
energy at variable rates less than full contract rates. Revenues for energy
delivered pursuant to special dispatch arrangements with Niagara Mohawk for
the year ended December 31, 1996 were approximately $29.0 thousand as
compared to approximately $5.1 million for the prior year. Revenues for the
year ended December 31, 1996 were also favorably impacted by increased energy
deliveries to Niagara Mohawk, as evidenced by the 300 basis point increase in
the capacity factor from December 31, 1995 to December 31, 1996.
Revenues from Con Edison increased $7.1 million for the year ended
December 31, 1996 as compared to the prior year. The increase in revenues is
primarily attributable to all delivered energy during the year ended December
31, 1996 being sold at full contract rates and higher contract energy rates
resulting from higher index fuel prices as compared to the prior year.
During the twelve months ended December 31, 1996, energy delivered to Con
Edison was sold entirely at full contract rates, whereas for the majority of
January 1995 and for a few days in February and April 1995, the Partnership
entered into special dispatch arrangements with Con Edison, at times when the
Unit would have otherwise been dispatched off-line. These special dispatch
arrangements called for the pricing of delivered energy at variable rates
less than full contract rates. Revenues for energy delivered pursuant to
special dispatch arrangements with Con Edison for the year ended December 31,
1995 was approximately $1.8 million. The increase in revenues for the year
ended December 31, 1996 was partially offset by a decrease in energy
deliveries, as evidenced by the 700 basis point decrease in the capacity
factor from December 31, 1995 to December 31,1996. The decrease in energy
deliveries was primarily due to a decrease in capacity during off-peak
periods.
21
<PAGE>
Steam revenues for the year ended December 31, 1996 were approximately
$2.7 million on 1,867.330 million pounds of steam delivered as compared to
approximately $2.0 million on 1,718.101 million pounds of steam delivered for
the prior year. Revenue per unit of steam increased during the year ended
December 31, 1996 as compared to the prior year. Higher index fuel pricing
and colder than normal winter months were the primary factors contributing to
the increase in steam revenues for the twelve months ended December 31, 1996
as compared to the prior year. Additionally, steam revenues for the year
ended December 31, 1996 include an annual true-up of $0.2 million in favor of
the steam host.
Gas resale revenues for the year ended December 31, 1996 were
approximately $24.6 million on sales of approximately 7.9 million MMBtu's as
compared to approximately $16.1 million on sales of approximately 8.0 million
MMBtu's for the prior year. The $8.5 million increase in gas resale revenues
during the year ended December 31, 1996 as compared to the prior year is
primarily due to an increase in average natural gas resale prices. The
increase in average natural gas resale prices generally resulted from the
colder than normal temperature this past winter which caused an increase in
demand for natural gas and resulted in lower than normal gas storage levels.
The decrease in gas resale volumes is attributable to the increase in the
capacity factor for Unit 1 sales to Niagara Mohawk. 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, 1996 were approximately $89.2
million on purchases of approximately 28.5 million MMBtu's as compared to
approximately $84.7 million on purchases of 30.2 million MMBtu's for the
prior year. The increase in the cost of fuel was primarily due to higher
contract firm fuel rates from higher index fuel prices and rate increases
under the firm transportation contracts. The 1.7 million MMBtu decrease for
the year ended December 31, 1996 as compared to the prior year is primarily
due to the negotiated temporary reduction in the maximum daily quantity and
related transportation under the Unit 1 Paramount Contract.
Operating and maintenance expenses for the year ended December 31, 1996
were approximately $17.9 million as compared to approximately $17.2 million
for the prior year. The $0.7 million increase in operating and maintenance
expenses during the year ended December 31, 1996 as compared to the prior
year was due to an increase in maintenance of the Facility.
22
<PAGE>
Total other operating expenses, excluding amortization of deferred
financing charges, for the year ended December 31, 1996 were approximately
$5.5 million as compared to approximately $6.0 million for the prior year.
The decrease in other operating expenses was primarily due to an overall
reduction in third party legal and consulting services.
Amortization of deferred financing charges for the year ended December
31, 1996 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, 1996 was
approximately $32.8 million as compared to approximately $32.4 million for
the prior year. The increase in net interest expense is primarily
attributable to approximately a $0.5 million decrease in interest income for
the year ended December 31, 1996 as compared to the corresponding period in
the prior year.
Liquidity and Capital Resources
Net cash provided by operating activities for the year ended December 31,
1997 was $27.1 million as compared to $32.6 million for the prior year. The
decrease in net cash from operating activities is due to the decrease in net
income and normally recurring changes in cash receipts and disbursements
within the Partnership's operating asset and liability accounts for the year
ended December 31, 1997 as compared to the prior year.
Net cash used in investing activities for the year ended December 31,
1997 was $1.3 million as compared to net cash provided by investing
activities of $3.6 million for the prior year. Net cash used in investing
activities for the year ended December 31, 1997 primarily represents the net
activity in the restricted cash accounts described below under "Funds". Net
cash provided by investing activities for the year end December 31, 1996
primarily represents the net activity in these restricted cash accounts
offset by the completion of certain construction-related activities.
Net cash used in financing activities for the year ended December 31,
1997 was $27.1 million as compared to $36.2 million for the prior year.
During the year ended December 31, 1997 approximately $24.9 million was
released for distribution to the partners as compared to approximately $35.5
million for the prior year.
The debt service coverage ratio for 1997 calculated pursuant to the
Indenture was 1.70:1.
Credit Agreement
The Partnership has available for its use a $23.5 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,
1997, no draws had been made against the outstanding letters of credit and no
working capital loans were outstanding under the Credit Agreement. Although
the Credit Agreement was originally due to expire on August 11, 1997 the
Partnership extended the Credit Agreement for an additional three years.
23
<PAGE>
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.
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, 1997 the
balance in this Fund was approximately $1.6 million, which exceeded the
current Fund Requirement.
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,
1997, the monies available in the Interest Fund were used to make the
semi-annual interest payment. Therefore, the balance in the Interest Fund at
December 31, 1997 was $0. The June 26, 1998 Interest and Principal Fund
Requirements will be approximately $17.2 million and approximately $1.9
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, 1997 the balance in this Fund was approximately $19.9
million. The June 26, 1998 Fund Requirement will be approximately $21.0
million.
24
<PAGE>
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.
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, 1998
During 1998, the Partnership anticipates its power purchasers will
dispatch their respective units in a manner consistent with the dispatch
levels in 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 results of
operations, including revenues and cash flows, of the Partnership. However,
if and when the restructured Niagara Mohawk Power Purchase Agreement goes
into effect, the Partnership anticipates that Niagara Mohawk will relinquish
its right to direct the dispatch of Unit 1 and that the Partnership would
make decisions regarding the operation of Unit 1 based on market conditions
then in effect, in light of its anticipated receipt of certain fixed payments
under the restructured Niagara Mohawk Power Purchase Agreement.
25
<PAGE>
As of March 1998, natural gas resale prices for 1998 have been below the
prior year's high prices and the Partnership expects, on the average, such
prices to remain below 1997 levels for the balance of 1998.
Future operating results and cash flows from operations are also
dependent on, among other things, the performance of equipment and processes
as expected, level of dispatch, fuel deliveries and prices as contracted and
the receipt of certain capacity and other fixed payments. A significant
change in any of these factors could have a material adverse effect on the
results for the Partnership.
The Partnership believes that based on current conditions and
circumstances it will have sufficient liquidity available provided by cash
flows from operations to fund existing debt obligations and operating costs.
Year 2000
The Partnership is conducting a review of its computer systems to
identify the systems that could be affected by the new millennium. The year
2000 may pose problems in software applications because many computer systems
and applications currently use two-digit date fields to designate a year. As
the century date occurs, date sensitive systems may recognize the year 2000
as 1900 or not at all. This potential inability to recognize or properly
treat the year 2000 may cause systems to process financial or operational
information incorrectly. Management has not yet determined which, if any,
systems may be affected and, if affected, the extent of any potential
disruption in operations and the resulting potential impact on the
Partnership's ability to generate and deliver electricity or steam.
Management has begun to develop and, if required, implement a plan to remedy
any potential problems prior to the year 2000. Management expects to
finalize this plan, if required, and estimate any potential expenses to
implement such plan, in 1998. Management has not yet assessed expenses
related to year 2000 compliance or the potential impacts of this matter.
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.
26
<PAGE>
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 J. Makowski Company. 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
---- --- --------
Joseph P. Kearney............51 Chief Executive Officer, President and
Director
P. Chrisman Iribe............46 Executive Vice President and Director
John R. Cooper...............50 Senior Vice President and Chief
Financial Officer
David N. Bassett.............51 Treasurer
Managing General Partner:
-------------------------
Name Age Position
---- --- --------
Joseph P. Kearney............51 Chief Executive Officer, President and
Director
P. Chrisman Iribe............46 Executive Vice President and Director
John R. Cooper...............50 Senior Vice President and Chief
Financial Officer
David N. Bassett.............51 Treasurer
Joseph P. Kearney has been President and Chief Executive Officer of U.S.
Generating Company ("U.S. Generating"), an affiliate of the Partnership,
since it was formed in 1989. Prior to joining U.S. Generating, Mr. Kearney
held senior management positions at the Coastal Corporation from 1984 to
1989. Prior to 1984, Mr. Kearney held positions in project and technology
development and financing with the Fluor Corporation, Enpex Corporation and
System Development Corporation. From 1974 to 1979, Mr. Kearney served as
Chief of Energy Technology, White House Office of Management & Budget. He
had Executive Office responsibility for financial, policy, legislative,
management and budgetary proposals by the U.S. Department of Energy and the
Nuclear Regulatory Commission.
27
<PAGE>
P. Chrisman Iribe is Executive Vice President 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 relations and public affairs with ANR Pipeline
Company, a natural gas pipeline company and a subsidiary of the Coastal
Corporation.
John R. Cooper is Senior Vice President 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.
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, 1997 to any of the officers, directors
and representatives referred to under Item 10 above for their services to the
Funding Corporation, the Managing General 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.
28
<PAGE>
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 JMC Selkirk, Inc. (3) Managing General (i) 2.0417%
Interest One Bowdoin Square Partner (ii) 22.4000%
Boston, Massachusetts 02114 Limited Partner (iii) 18.1440%
Partnership Pentagen Investors, L.P.*(3)(4) Limited Partner (i) 5.2502%
Interest One Bowdoin Square (ii) 57.6000%
Boston, Massachusetts 02114 (iii) 46.6560%
Partnership Cogen Technologies General Partner (i) 1.0000%
Interest Selkirk GP, Inc. (iii) .2211%
1600 Smith Street
Houston, Texas 77002 (5)
Partnership Cogen Technologies Limited Partner (i) 78.1557%
Interest Selkirk LP. (iii) 17.2789%
1600 Smith Street
Houston, Texas 77002 (5)
Partnership EI Selkirk, Inc. (6) Limited Partner (i) 13.5523%
Interest 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 period following the completion of Unit 2 (or, if later, the date
when all Level I Distributions have been paid).
(3) J. Makowski Company is the indirect beneficial owner of JMC Selkirk and a
50% indirect beneficial owner of Investors (formerly known as JMCS I
Investors, L.P.). All of the capital stock of J. Makowski Company is
held by Beale Generating Company, a special purpose corporation jointly
owned by subsidiaries of PG&E Enterprises and Bechtel Enterprises, Inc.
29
<PAGE>
(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%). Cogen Technologies LP is beneficially
owned by Robert C. McNair (72.155%), members of his family (9.561%) and
certain of his associates (18.284%). 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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- --------------------------------------------------------
JMCS I Management, a wholly-owned indirect subsidiary of J. Makowski
Company, 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.
30
<PAGE>
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 Auditor.................................... F-1
Balance Sheets as of December 31, 1997 and 1996 ................. F-2
Statements of Operations for the years ended December 31, 1997,
1996 and 1995 ................................................... F-3
Statements of Partners' Capital for the years ended December 31,
1997, 1996 and 1995 ............................................. F-4
Statements of Cash Flows for the years ended December 31, 1997,
1996 and 1995.................................................... 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
Not applicable
31
<PAGE>
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, 1997 and 1996, and the related consolidated statements of
operations, partners' capital and cash flows for the years then ended. These
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, 1997 and
1996, and the results of their operations and their cash flows for the years
then ended, 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
the accompanying index 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, 1998
F-1
<PAGE>
<TABLE>
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(in thousands)
<CAPTION>
December 31, December 31,
1997 1996
----------- -----------
<S> <C> <C>
ASSETS
- ------
Current assets:
Cash............................................ $ 1,337 $ 2,591
Restricted funds................................ 6,509 6,284
Accounts receivable............................. 17,764 19,899
Due from affiliates............................. 14 40
Fuel inventory and supplies..................... 4,936 4,401
Other current assets............................ 338 449
--------- ---------
Total current assets...................... 30,898 33,664
Plant and equipment............................. 371,285 371,301
Less: Accumulated depreciation................. 49,748 37,072
--------- ---------
Net plant and equipment....................... 321,537 334,229
Long-term restricted funds...................... 21,494 20,446
Deferred financing charges, net of accumulated
amortization of $4,336 at December 31, 1997
and $3,166 at December 31, 1996............... 11,945 13,115
--------- ---------
Total Assets $ 385,874 $ 401,454
--------- ---------
--------- ---------
LIABILITIES AND PARTNERS' CAPITAL
- ---------------------------------
Current liabilities:
Accounts payable................................ $ 1,663 $ 588
Accrued expenses................................ 15,047 16,624
Due to affiliates............................... 498 937
Advances from customer.......................... --- 17
Current portion of long-term bonds.............. 3,298 2,167
--------- ---------
Total current liabilities................. 20,506 20,333
Other long-term liabilities..................... 11,695 10,678
Long-term bonds, less current portion........... 385,955 389,253
General partners' capital....................... (311) (173)
Limited partners' capital....................... (31,971) (18,637)
--------- ---------
Total partners' capital................... (32,282) (18,810)
--------- ---------
Total Liabilities and
Partners' Capital $ 385,874 $ 401,454
--------- ---------
--------- ---------
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
F-2
<PAGE>
<TABLE>
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
<CAPTION>
For the For the For the
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Operating revenues:
Electric and steam.......... $ 157,940 $ 149,793 $ 139,637
Gas resale.................. 13,643 24,649 16,141
---------- ----------- ------------
Total operating
revenues................. 171,583 174,442 155,778
Cost of revenues:
Fuel costs................. 90,526 89,177 84,712
Other operating and
maintenance expenses....... 18,103 17,913 17,217
Depreciation............... 12,676 12,657 12,562
--------- --------- ---------
Total cost of revenues... 121,305 119,747 114,491
--------- --------- ---------
Gross Profit................. 50,278 54,695 41,287
Other operating expenses:
Administrative services -
affiliates................ 2,852 2,715 2,419
Other general and
administrative expenses... 2,562 2,781 3,625
Amortization of deferred
financing charges......... 1,170 1,173 1,130
--------- --------- ---------
Total other operating
expenses............... 6,584 6,669 7,174
--------- --------- ---------
Operating income............. 43,694 48,026 34,113
Net interest expense......... 32,234 32,844 32,392
--------- --------- ---------
Net income .................. $ 11,460 $ 15,182 $ 1,721
--------- -------- ---------
--------- -------- ---------
Allocated to:
General partners........... $ 115 $ 152 $ 41
Limited partners........... 11,345 15,030 1,680
--------- --------- ---------
Total.................... $ 11,460 $ 15,182 $ 1,721
--------- --------- ---------
--------- --------- ---------
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
F-3
<PAGE>
<TABLE>
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
For the years ended December 31, 1997, 1996 and 1995
(in thousands)
<CAPTION>
General Limited
Partners Partners Total
---------- ---------- ------------
<S> <C> <C> <C>
Balance at December 31, 1994.. $ (3,718) $ 24,539 $ 20,821
Cash distributions.......... (691) (20,321) (21,012)
Conversion and Assignment
of JMCS I Investors, L.P.
Interest (see Note 3 to
the consolidated
financial statements).... 4,411 (4,411) ---
Net Income.................. 41 1,680 1,721
--------- --------- ---------
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)
--------- --------- ---------
--------- --------- ---------
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
F-4
<PAGE>
<TABLE>
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
<CAPTION>
For the For the For the
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Net cash provided by(used
in) operating activities:
Net income ................ $ 11,460 $ 15,182 $ 1,721
Adjustments to reconcile net
income to net cash
provided by (used in)
operating activities:
Depreciation and
amortization........... 13,846 13,830 13,692
Change in assets and
liabilities:
Accounts receivable... 2,135 (2,582) (2,791)
Due from affiliates... 26 (23) 174
Other current assets.. 111 563 (195)
Fuel inventory and
supplies............ (535) (828) 466
Accounts payable....... 1,075 216 (3,394)
Accrued expenses....... (1,577) 3,376 905
Due to affiliates...... (439) 675 (381)
Other long-term
liabilities.......... 1,017 2,163 1,968
--------- --------- --------
Total adjustments.... 15,659 17,390 10,444
--------- --------- ---------
Net cash provided
by operating
activities...... 27,119 32,572 12,165
Cash flows provided by (used
in) investing activities:
Plant and equipment
additions.............. 16 (601) (4,275)
Plant and equipment
additions-affiliates... --- --- (132)
Restricted funds......... (1,273) 4,186 17,689
--------- --------- ---------
Net cash provided
by (used in)
investing
activities...... (1,257) 3,585 13,282
Cash flows provided by (used
in) financing activities:
Cash distributions to
partners................ (24,932) (35,522) (21,012)
Payments of principal on
long-term debt.......... (2,167) (580) ---
Payments for cost of
financing............... --- --- (217)
Advances from a customer.. (17) (136) (5,282)
--------- --------- ---------
Net cash used in
financing
activities....... (27,116) (36,238) (26,511)
Net decrease in cash........ (1,254) (81) (1,064)
Cash at beginning of
periood................... 2,591 2,672 3,736
--------- --------- ---------
Cash at end of periood..... $ 1,337 $ 2,591 $ 2,672
--------- --------- ---------
--------- --------- ---------
Supplemental disclosures of
cash flow information:
Cash paid for interest... $ 34,561 $ 34,781 $ 35,160
--------- --------- ---------
--------- --------- ---------
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
F-5
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997 AND 1996
1. Organization and business
-------------------------
Selkirk Cogen Partners, L.P. (Selkirk or 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).
Selkirk was formed for the purpose of constructing, owning and operating
a natural gas-fired combined-cycle cogeneration facility located on
General Electric Company's (GE) 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. Selkirk 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). Unit 1 is selling
at least 79.9 MW of electric capacity and associated energy to Niagara
Mohawk Power Corporation (NIMO) under a 20-year contract and Unit 2 is
selling 265 MW of electric capacity and associated energy to Consolidated
Edison Company of New York (ConEd) 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). Historical
natural gas resale prices have resulted in significant gas resale margins
for the Partnership during the years ended December 31, 1997 and 1996.
Historical natural gas prices may not be indicative of future natural gas
market prices.
Unit 1 of the Facility is currently certified as a qualifying facility
(QF) 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 FERC as a QF. However, this is not expected to have a
material impact on Selkirk's financial position or operations. Certain
fuel transportation agreements entered into by Selkirk are subject to
regulation on the federal and provincial levels in Canada. Selkirk has
obtained all material Canadian governmental permits and authorizations
required for operation.
F-6
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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.
The statements of operations for the years ended December 31, 1997, 1996
and 1995 include the activities of the Funding Corporation. All
intercompany balances and transactions have been eliminated in
consolidation.
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.
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.
F-7
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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 maintenance and repairs reserve is recorded based upon scheduled major
maintenance plans for 20 years. Other maintenance and repairs are
charged to expense as incurred.
Fuel inventory and supplies
---------------------------
Inventories are stated at the lower of cost or market. Costs for
materials, supplies and oil inventories were determined on an average
cost method.
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.
Accrued expenses
----------------
Accrued expenses consist of the following (in thousands):
December 31, December 31,
1997 1996
------------ ------------
Accrued fuel costs $ 10,002 $ 12,250
Accrued wheeling --- 466
Accrued PILOT 1,150 1,050
Accrued NY gas import taxes 260 114
Accrued utilities 924 982
Accrued plant purchases 391 518
Accrued bond interest 382 385
Accrued GE steam refund 668 175
Other accrued expenses 1,270 684
--------- ---------
$ 15,047 $ 16,624
--------- ---------
--------- ---------
F-8
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Currency swap agreements
------------------------
In connection with its asset and liability management policies, Selkirk
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 losses on
the associated swap agreement will be recorded in the income statement.
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 pronouncement
----------------------------
During 1997, the Financial Accounting Standards Board issued two new
accounting standards that the Partnership will adopt in 1998. SFAS No.
130, "Reporting Comprehensive Income" will require disclosure on
comprehensive income and its components. SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information" will require
disclosure of financial and descriptive information on reportable
operating segments. The adoption of these standards is not expected to
have a material impact on the Partnership's results of operations or
financial position.
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.
F-9
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The general and limited partners, along with their respective equity
interests are as follows:
Interest
General partners Affiliate of Preferred Original
---------------- ------------ --------- --------
JMC Selkirk, Inc. J. Makowski Company, Inc. (JMC) .09% 1.00%
Cogen Technologies
Selkirk GP, Inc. Cogen Technologies, Inc. 1.00% ---%
Interest
Limited partners Affiliate of Preferred Original
---------------- ------------ --------- --------
JMC Selkirk, Inc. J. Makowski Company, Inc. 1.95% 21.40%
Pentagen Investors, L.P. J. Makowski Company, Inc. 5.25% 57.60%
EI Selkirk, Inc. GPU International, Inc. 13.55% 20.00%
Cogen Technologies
Selkirk, L.P. Cogen Technologies, Inc. 78.16% ---%
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 JMC affiliates and GPU
International, Inc. (GPUI). Any additional funds available after the
preferred 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; JMC
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, a wholly-owned subsidiary of the
Partnership, 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.
F-10
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The scheduled principal payments on the bonds are as follows:
1998 $ 3,297,597
1999 4,822,151
2000 7,306,785
2001 11,062,070
2002 13,528,965
Thereafter 349,235,385
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 Selkirk to make distributions to the partners under
certain circumstances.
In connection with the bonds, the Partnership is required to maintain
certain restricted funds to finance future debt, interest and maintenance
payments. These funds have been included in restricted funds and
long-term restricted funds in the accompanying balance sheet. For
further discussion of these funds see Management's Discussion and
Analysis.
In 1994, Selkirk entered into a combined working capital and bank
reimbursement agreement, as amended (Credit Agreement). The Credit
Agreement has a maximum available amount of $23,471,420 to be used by
Selkirk for required letters of credit related to various project
contracts and working capital purposes. The maximum amount available
under the Credit Agreement for working capital purposes is $5,000,000.
No amounts have been drawn under the Credit Agreement.
Currency swap agreements
------------------------
On June 20, 1990 and October 29, 1992, Selkirk 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 Selkirk 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 Selkirk 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.
F-11
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Selkirk is exposed to credit loss under the currency agreements. In the
unlikely event that a counterparty fails to meet the terms of the
agreements, Selkirk's exposure is limited to the currency exchange rate
differential. However, Selkirk does not anticipate nonperformance by the
counterparties.
5. Disclosure of fair market 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, 1997 and 1996:
Cash: The carrying amount reported in the accompanying balance sheets
for cash approximates its fair value of $1,337,000 and $2,591,000 at
December 31, 1997 and 1996, respectively.
Restricted funds: The carrying amount reported in the accompanying
balance sheets for restricted funds approximates its fair value of
$28,003,000 and $26,730,000 at December 31, 1997 and 1996, respectively.
Due from affiliates: Management believes that estimating the fair market
value of these advances is not practicable given no formal agreement
between the Partnership and its affiliates regarding the terms and manner
of settlement 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.
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, 1997 and 1996 is
approximately $404,282,956 and $391,723,132, respectively.
Currency swap agreements: The fair value of the currency exchange
arrangements represents the termination value (liability) of
approximately $10,535,000 and $6,588,000 at December 31, 1997 and 1996,
respectively, estimated using current exchange rates.
F-12
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
6. Commitments
-----------
Selkirk 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, Selkirk is obligated under the following
agreements:
Power sales agreements - electricity
------------------------------------
In December 1987, Selkirk entered into a power sales agreement, as
amended, with NIMO, for the sale of electricity, for an initial term of
20 years commencing on the date of commercial operations, April 17, 1992.
The agreement may be terminated upon two years written notice to NIMO and
payment of a termination fee or upon the loss of Selkirk's status as a
QF.
In April 1994, the power sales agreement with NIMO was amended and,
pursuant to this amended agreement, the Partnership paid NIMO $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.
On October 6, 1995, NIMO filed its "Power Choice" proposal with the New
York State Public Service Commission ("NYPSC"). On October 12, 1995,
NIMO filed a Report on Form 8-K with the Securities and Exchange
Commission (the "Commission") explaining the Power Choice proposal (the
"Power Choice Statement"). In the Power Choice Statement, NIMO describes
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"). On July 10, 1997, NIMO filed a
Report on Form 8-K with the Commission stating that NIMO had entered into
a Master Restructuring Agreement ("MRA") pursuant to which it and the
twenty-nine independent power producers which had signed the MRA propose
to terminate, restate or amend their respective power sales agreements.
On October 17, 1997, NIMO filed a Report on Form 8-K with the Commission
stating that on October 11, 1997, NIMO filed its Power Choice settlement
with the NYPSC which incorporates the terms of the MRA. On February 24,
1998, the NYPSC approved NIMO's Power Choice settlement proposal, which
includes the implementation of the MRA.
F-13
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The consideration for the independent power sellers' agreement varies by
party, and may consist of cash, short term notes, shares of NIMO's Common
Stock or certain swap contracts. Among the contracts which is proposed
to be restructured is the NIMO power sales agreement for the electric
output of Unit 1. Pursuant to the MRA and subject to implementation as
described below, the parties propose to restructure the NIMO power sales
agreement to provide for the sale of electricity by the Partnership
pursuant to a pre-determined schedule of output at a price based on
certain indices for a period of 10 years in lieu of the delivery and
price provisions of the NIMO power sales agreement as currently in
effect. The Partnership anticipates that, if and when a restructured
power sales agreement goes into effect, NIMO will relinquish its right to
direct dispatch of Unit 1, the electrical output of Unit 1 will be sold
to NIMO and other purchasers based on market conditions then in effect,
and the Partnership will receive certain fixed payments from NIMO under
the restructured power sales agreement and other payments under the MRA.
The details of the physical delivery and pricing arrangements are subject
to final agreement with NIMO, and possible modifications to other
Partnership contracts for Unit 1 continue to be the subject of extensive
negotiations. Implementation of the MRA is subject to a number of
significant conditions, including without limitation NIMO and the
Partnership negotiating the restructured Unit 1 power sales agreement,
the receipt of all regulatory approvals, the receipt of all consents by
third parties necessary for the transaction contemplated by the MRA
(including satisfying certain standards under the Partnership's trust
indenture relating to the absence of material adverse changes or
receiving any required approval of bondholders or other creditors), the
Partnership's entering into new third party arrangements which will
enable the Partnership to restructure its project on a reasonably
satisfactory economic basis, and the receipt by NIMO and the Partnership
of all necessary approvals from their respective boards of directors,
shareholders and partners. Should NIMO and the Partnership satisfy all
of the conditions to effectuating the transactions contemplated by the
MRA with respect to the Partnership, NIMO may nevertheless terminate the
MRA if NIMO determines that, as a result of the failure to satisfy the
conditions of the MRA by other independent power producers, the benefits
anticipated to be received by NIMO pursuant to the MRA have been
materially and adversely affected. Further, final implementation of the
MRA is conditioned upon NIMO's successful completion of financing
required to fund certain of its payment obligations under agreements to
implement the MRA.
F-14
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The Partnership, as a party to the MRA, is committed to negotiate with
NIMO and other parties to reach agreement on contractual arrangements
required to restructure the NIMO power sales agreement pursuant to the
MRA; however, the Partnership expresses no opinion with respect to the
likelihood that all of the conditions to implementation of the MRA will
be met. Further, the Partnership expresses no opinion with respect to
the viability of NIMO's proposed alternatives should the implementation
of the MRA not be completed, such as NIMO's proposal in the context of
the Power Choice Statement to take possession of independent power
projects through the power of eminent domain and to thereafter sell such
projects or NIMO's position that it has not ruled out the ultimate
possibility of a filing for restructuring under Chapter 11 of the U.S.
Bankruptcy Code as set forth in the Power Choice Statement.
Nevertheless, in the absence of agreement on a definitive restructured
power sales agreement, the Partnership continues to believe that the NIMO
power sales agreement is a valid and binding contract with NIMO. Given
the uncertainties with respect to such implementation, the Partnership is
unable to determine what effect, if any, the restructured power sales
agreement or the Power Choice proposal will have on the Partnership, its
business or net operating revenues. For the year ended December 31,
1997, electric sales to NIMO accounted for approximately 19.3% of total
project revenues.
Previously, in connection with NIMO's March 10, 1997 announcement of the
agreement in principle, Standard & Poor's placed the bonds on creditwatch
"with negative implications," based in part on its analysis of the
current reports on Form 8-K filed in March 1997 by NIMO and the
Partnership, respectively, and its belief that the restructuring has the
potential to erode cash flow coverage derived from long-term contracts
supporting the bonds. To date Standard & Poor's has not changed their
outlook on the bonds. Additionally, as of the date of this report,
Moody's Investors Service has not changed its rating or its previous
"negative outlook" on the bonds as a result of the developments.
Selkirk has also entered into a power sales agreement with ConEd, 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, Selkirk provided ConEd 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 ConEd power sales agreement and
expired on February 6, 1996.
The power sales agreements with NIMO and ConEd each provide the
purchasing utility with the contractual right to schedule the related
Unit for dispatch on a daily basis at full capability, partial capability
or off-line. Each purchasing utility'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 NIMO and ConEd if Selkirk does not maintain a
minimum availability level.
F-15
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
ConEd, by a letter dated September 19, 1994, claimed the right to acquire
that portion of Unit 2's natural gas supply not used in operating Unit 2
(the "excess gas"), when Unit 2 is dispatched off-line or at less than
full capability. The ConEd power sales agreement contains no express
language granting ConEd any rights to such excess gas and the Partnership
has stated to ConEd that claims to excess gas are without merit. To date
ConEd has paid all amounts invoiced by the Partnership in accordance with
the ConEd power purchase agreement.
If ConEd were to prevail in its claim to Unit 2's excess natural gas
volumes, the Partnership would lose its ability to engage in lay-off
sales of such volumes at favorable prices relative to their costs, and
thus the Partnership's cash flows from gas resale activities would also
be materially and adversely affected. The Partnership is unable to
determine the outcome of this uncertainty.
In August 1992, NIMO filed a petition requesting the NYPSC to authorize
NIMO to curtail purchases from, and avoid payment obligations to,
non-utility generators, including QF's such as the Facility during
certain periods. NIMO claimed that such curtailment would be consistent
with PURPA, and the regulations promulgated thereunder, which
contemplates utilities' curtailing purchases from QF'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. ConEd 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. The
Partnership expects that any agreement which it enters into with NIMO to
implement the MRA will waive NIMO's right, if any, to curtail purchases
from the Partnership. See Part I Item 1. Business - The Facility and
Certain Project Contracts - Niagara Mohawk for discussion of the MRA.
F-16
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
In any event, 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 NIMO and ConEd some measure of
generic curtailment rights. The Partnership's position is based in part
on the fact that neither NIMO nor ConEd bargained for an express
curtailment right in its power sales agreement and the Partnership agreed
to permit NIMO and ConEd to direct the dispatch of the relevant Unit.
Nevertheless, both NIMO and ConEd have refused to expressly waive their
claimed curtailment rights against dispatchable facilities and have not
agreed to exempt the Facility from curtailment, notwithstanding the
absence of contractual language in the power sales agreements granting
the utilities this right. If NIMO and ConEd were to receive NYPSC
authorization to curtail power purchases from QF's including dispatchable
facilities, they may seek to implement curtailment with respect to the
Partnership by avoiding not only energy p ayments 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, Selkirk entered into a steam sales agreement for Unit
1, as amended, with GE for an initial term of 20 years, effective from
the date of commercial operations. On October 21, 1992, Selkirk and GE
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, GE had agreed to forego
(subject to later repayment plus interest) the discount on a certain
quantity of steam supplied by Selkirk during a quarter to the extent
necessary for Selkirk to maintain a quarterly debt service coverage ratio
of 1.2 to 1 and the advances, with interest, are repayable to the extent
Selkirk's quarterly debt service coverage ratio exceeds 1.3 to 1. Under
this agreement, Selkirk had invoiced and received from GE 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.
GE is obligated under the steam sales agreement to purchase the minimum
quantities of steam necessary for the Facility to maintain its QF status.
In the event that GE 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.
F-17
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The agreement provides GE the right of first refusal to purchase the
Facility, subject to certain pricing considerations. Additionally, GE
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 agreement may be terminated by Selkirk with
one year's written notice if either the NIMO or ConEd power sales
agreement is terminated. It may also be terminated by GE with two years'
written notice if GE's plant no longer has a requirement for steam.
Fuel supply and transportation agreements
-----------------------------------------
Selkirk 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 5 years upon satisfaction of
certain conditions.
Selkirk 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 Selkirk 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 $38,279,000, $35,191,000 and $28,736,000 in gas
from these suppliers for the years ended December 31, 1997, 1996 and
1995, respectively.
Selkirk 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, Selkirk posted a letter of credit in the amount
of approximately $586,000 in October 1992.
Selkirk 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. Upon the execution of the transportation agreement
with one transporter, the various fuel suppliers posted letters of credit
totaling approximately $10,007,000 Canadian dollars for the benefit of
the transporter on behalf of Selkirk which was subsequently reduced to
approximately $9,814,000 Canadian dollars in February 1997. Selkirk will
reimburse all costs related to obtaining and maintaining the letters of
credit. Selkirk also posted two letters of credit related to the
remaining two firm fuel transportation agreements for approximately
$796,000 and $2,090,000.
F-18
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Electric interconnection and transmission agreements
----------------------------------------------------
Selkirk constructed an interconnection facility to transfer power from
Unit 1 to NIMO and transferred title of the facility to NIMO. Selkirk
has agreed to reimburse NIMO $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 sales agreement with NIMO is extended.
In December 1990, Selkirk entered into a 20-year firm interruptible
transmission agreement with NIMO, as amended, to transmit power from Unit
2 to ConEd, beginning with commercial operations. In connection with
this agreement, Selkirk constructed an interconnection facility and
transferred title to NIMO in 1995. Under the terms of this agreement,
Selkirk will reimburse NIMO $450,000 annually for the maintenance of the
facility.
Site lease
----------
Rent expense was approximately $1,000,000, for the years ended December
31, 1997, 1996 and 1995. 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
Selkirk under certain circumstances with the appropriate written notice
during the initial term.
Payment in lieu of taxes agreement
----------------------------------
In October 1992, Selkirk 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 Selkirk from all property
taxes, except for special assessments. The agreement commenced on
January 1, 1993, and terminates on December 31, 2012.
On the closing date of the facility lease agreement with the IDA, Selkirk
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:
F-19
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
1998 $ 2,300,000
1999 2,500,000
2000 2,700,000
2001 2,900,000
2002 3,100,000
Thereafter 39,200,000
Other agreements
----------------
Selkirk has an operations and maintenance services agreement with GE
whereby GE 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, Selkirk has entered into a 20-year take or pay
water supply agreement with the Town of Bethlehem under which Selkirk 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
---------------
An affiliate of JMC Selkirk, Inc. has been appointed project
administrative agent to manage the day-to-day affairs of Selkirk. 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, 1997, 1996 and 1995 approximately
$2,852,000, $2,715,000 and $2,419,000, respectively was incurred for
services rendered and is reflected in general and administrative expenses
in the statement of operations.
During the years ended December 31, 1997, 1996 and 1995, Selkirk
purchased approximately $346,000, $16,000 and $3,877,000, respectively
and sold approximately $26,000, $238,000 and $748,000, respectively in
fuel at its fair market value in transactions with affiliates of JMC
Selkirk, Inc. Purchases are included in fuel costs and sales are included
in gas resales in the statements of operations.
F-20
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
During the year ended December 31, 1996, Selkirk entered into an Enabling
Agreement with US Gen Power Services, L.P.("USGEN PS"), an affiliate of
JMC Selkirk, Inc., to enter into certain transactions for the purchase
and sale of energy and other services. During the years ended December
31, 1997 and 1996, Selkirk entered into energy and capacity sale
transactions with USGEN PS totaling approximately $100,000 and $45,000,
respectively.
Selkirk 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.
8. Contingency
-----------
In connection with transactions in 1994 involving the investment by
affiliates of Cogen Technology, Inc. in the Partnership and the purchase
of J. Makowski Company, Inc. by Beale Generating Company, the Partnership
filed New York State real estate transfer and gains tax returns with New
York tax authorities. The New York tax authorities have raised certain
questions and issues about such tax returns.
In January 1998, the Partnership received a letter from the New York tax
authorities concluding that no additional real estate transfer tax is due
on the transfers made by the shareholders of J. Makowski Co. Inc. and the
Partnership and has closed the audit file.
F-21
<PAGE>
<TABLE>
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS
- ---------------------------------------------
<CAPTION>
Additions
--------------------
Charged
Balance at Charged to to Other Balance at
Beginning Costs and Accounts Deductions End of
Description of Period Expenses Describe Describe Period
- ----------- --------- -------- -------- ---------- ---------
<S> <C> <C> <C> <C> <C>
Deducted from
asset account-
allowance for
doubtful accounts:
Year Ended
December 31, 1997 $ - $ - $ - $ - $ -
--------- -------- --------- -------- --------
--------- -------- --------- -------- --------
Year Ended
December 31, 1996 $ 87,181 - $ - $ 87,181(1) $ -
--------- -------- --------- -------- --------
--------- -------- --------- -------- --------
Year Ended
December 31, 1995 $ 165,105 $ 87,181 $ - $165,105(2) $ 87,181
--------- -------- --------- -------- --------
--------- -------- --------- -------- --------
<FN>
(1) Represents the settlement of August and September 1995 capacity payment
issue.
(2) Represent the settlement of October and November 1993 capacity payment
issue.
S-1
</TABLE>
<PAGE>
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
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
32
<PAGE>
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(7) Amendment No. 2 to Credit Agreement, dated April 7, 1995,
between the Partnership and Dresdner Bank AG, New York Branch
10.1.4(7) Amendment No. 3 to Credit Agreement, dated July 1, 1997,
between the Partnership and Dresdner Bank AG, New York Branch
10.1.5(1) Loan Agreement, dated as of May 1, 1994, between the
Partnership, Chase, as Agent, and other Bridge Banks
identified therein
10.1.6(1) Amended and Restated Loan Agreement, dated as of May 1, 1994,
between the Funding Corporation and the Partnership
10.1.7(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
10.1.8(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
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(4) Fourth Amendment to Power Purchase Agreement, dated as of
June 26, 1996 between the Partnership and Niagara Mohawk
10.2.6(1) Agreement dated as of March 31, 1994, between the Partnership
and Niagara Mohawk
33
<PAGE>
10.2.7(6) Letter Agreement dated as of April 18, 1997, between the
Partnership and Niagara Mohawk
10.2.8(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
10.2.9(1) License Agreement between the Partnership and Niagara Mohawk,
dated as of October 23, 1992
10.2.10(1) Power Purchase Agreement, dated as of April 14, 1989, between
Con Edison Company of New York, Inc. ("Con Edison") and JMC
Selkirk
10.2.11(1) Rider to Power Purchase Agreement, dated as of September 13,
1989, between Con Edison and JMC Selkirk
10.2.12(1) First Amendment to Power Purchase Agreement, dated as of
September 13, 1991, between Con Edison and JMC Selkirk
10.2.13(1) Letter Agreement Regarding Extending the Term of the Power
Purchase Agreement, dated as of May 28, 1992, between Con
Edison and JMC Selkirk
10.2.14(1) Second Amendment to Power Purchase Agreement, dated as of
October 22, 1992, between Con Edison and JMC Selkirk
10.2.15(5) Third Amendment to Power Purchase Agreement, dated as of
September 13, 1996, between Con Edison and the Partnership
10.2.16(1) Letter Agreement Regarding Arbitration, dated October 22,
1992, between Con Edison and JMC Selkirk
10.2.17(1) Letter Agreement Regarding Sale of Capacity above 265 MW,
dated as of October 22, 1992, between Con Edison and JMC
Selkirk
10.2.18(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
10.2.19(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")
34
<PAGE>
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
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) Letter Agreement, dated as of October 25, 1993, between the
Partnership and Paramount
10.5.4(1) Second Amendment to the Amended and Restated Gas Purchase
Contract, dated as of December 1, 1993, between Paramount and
the Partnership
10.5.5(1) Indemnity Agreement, dated as of February 20, 1989, by the
Partnership in favor of Paramount
10.5.6(1) Letter Agreement, dated as of June 11, 1990, between the
Partnership and Paramount
10.5.7(1) Indemnity Amending and Supplemental Agreement, dated as of
June 19, 1990, between the Partnership and Paramount
35
<PAGE>
10.5.8(1) Intercreditor Agreement, dated as of October 21, 1992,
between Paramount, the Partnership and Chase, as Agent
10.5.9(1) Specific Assignment of Unit 1 TransCanada Transportation
Contract, dated as of December 20, 1991, by the Partnership
to Paramount
10.5.10(1) Amendment No. 1 to Specific Assignment, dated as of October
21, 1992, between the Partnership and Paramount
10.5.11(1) Amended and Restated Gas Purchase Agreement, dated as of
January 21, 1993, between the Partnership and Atcor Ltd.
("Atcor")
10.5.12(1) Amended and Restated Gas Purchase Agreement, dated as of
October 22, 1992, between the Partnership, as assignee, and
Imperial Oil Resources ("Imperial")
10.5.13(1) Amended and Restated Gas Purchase Agreement, dated as of
October 22, 1992, between the Partnership, as assignee, and
PanCanadian Pertroleum Limited ("PanCanadian")
10.5.14(1) Back-up Fuel Supply Agreement, dated as of June 18, 1992,
between Phibro Energy USA, Inc. ("Phibro") and SCP II
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(1) Firm Natural Gas Transportation Agreement, dated as of April
18, 1991, between Tennessee Gas Pipeline and the Partnership
10.6.6(1) Clarification Letter from Tennessee, dated April 18, 1991,
between the Partnership and Tennessee
36
<PAGE>
10.6.7(1) Supplemental Agreement (Unit 1), dated April 18, 1991,
between the Partnership and Tennessee
10.6.8(1) Operational Balancing Agreement, dated as of September 1,
1993, between the Partnership and Tennessee
10.6.9(1) Interruptible Transportation Agreement, dated as of September
1, 1993, between the Partnership and Tennessee
10.6.10(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
10.6.11(1) Firm Service Contract for Firm Transportation Service, dated
as of March 16, 1994, between the Partnership and TransCanada
10.6.12(1) Letter Agreement, dated as of March 24, 1994, between the
Partnership and TransCanada
10.6.13(1) Gas Transportation Contract for Firm Reserved Service, dated
as of April 5, 1994, between the Partnership and Iroquois
10.6.14(1) Letter Agreement, dated as of March 31, 1994, between the
Partnership and Iroquois
10.6.15(1) Firm Natural Gas Transportation Agreement, dated as of April
11, 1994, between the Partnership and Tennessee
10.6.16(1) Tennessee Supplemental Agreement (Unit 2), dated as of
October 21, 1992, between Tennessee and the Partnership
10.6.17(1) Letter Agreement, dated September 22, 1993, between the
Partnership and Tennessee
10.6.18(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
37
<PAGE>
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
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
38
<PAGE>
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
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
39
<PAGE>
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
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
40
<PAGE>
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
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(8) Master Restructuring Agreement, dated as of July 9, 1997,
among Niagara Mohawk, the Partnership and other Independent
Power Producers (defined therein)
16(3) Letter from former accountant (Ernst & Young, LLP), dated as
of February 13, 1995, 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)
41
<PAGE>
- -------------------
(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 Annual Report on
Form 10-K for the Fiscal Year Ended December 31, 1995 filed March 29, 1996.
(4) 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.
(5) 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.
(6) 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.
(7) 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.
(8) Incorporated herein by reference to Exhibit Number 10.28 of the Current
Report on Form 8-K of Niagara Moawk Power Corporation filed July 10, 1997.
42
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized.
SELKIRK COGEN PARTNERS, L.P.
Date: March 31, 1998 /s/ JMC SELKIRK, INC.
--------------------------
General Partner
Date: March 31, 1998 /s/ JOHN R. COOPER
--------------------------
Name: John R. Cooper
Title: Senior Vice President and
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/ JOSEPH P. KEARNEY Chief Executive Officer, March 31, 1998
- --------------------- President and Director
Joseph P. Kearney
/s/ P. CHRISMAN IRIBE Executive Vice President March 31, 1998
- --------------------- and Director
P. Chrisman Iribe
/s/ JOHN R. COOPER Senior Vice President and March 31, 1998
- --------------------- Chief Financial Officer
John R. Cooper
/s/ DAVID N. BASSETT Treasurer March 31, 1998
- ---------------------
David N. Bassett
43
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized.
SELKIRK COGEN FUNDING
CORPORATION
Date: March 31, 1998 /s/ JOHN R. COOPER
--------------------------
Name: John R. Cooper
Title: Senior Vice President and
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/ JOSEPH P. KEARNEY Chief Executive Officer, March 31, 1998
- --------------------- President and Director
Joseph P. Kearney
/s/ P. CHRISMAN IRIBE Executive Vice President March 31, 1998
- --------------------- and Director
P. Chrisman Iribe
/s/ JOHN R. COOPER Senior Vice President and March 31, 1998
- --------------------- Chief Financial Officer
John R. Cooper
/s/ DAVID N. BASSETT Treasurer March 31, 1998
- ---------------------
David N. Bassett
44
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 000929540
<NAME> SELKIRK COGEN PARTNERS, L.P.
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> Dec-31-1997
<PERIOD-START> Jan-01-1997
<PERIOD-END> Dec-31-1997
<CASH> 7846
<SECURITIES> 0
<RECEIVABLES> 17778
<ALLOWANCES> 0
<INVENTORY> 4936
<CURRENT-ASSETS> 30898
<PP&E> 371285
<DEPRECIATION> 49748
<TOTAL-ASSETS> 385874
<CURRENT-LIABILITIES> 20506
<BONDS> 385955
0
0
<COMMON> 0
<OTHER-SE> (32282)
<TOTAL-LIABILITY-AND-EQUITY> 385874
<SALES> 171583
<TOTAL-REVENUES> 171583
<CGS> 121305
<TOTAL-COSTS> 121305
<OTHER-EXPENSES> 6584
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 32234
<INCOME-PRETAX> 11460
<INCOME-TAX> 0
<INCOME-CONTINUING> 11460
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 11460
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
