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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999
Commission File Number 33-83618
SELKIRK COGEN PARTNERS, L.P.
(Exact name of Registrant (Guarantor) as specified in its charter)
Delaware 51-0324332
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
SELKIRK COGEN FUNDING CORPORATION
(Exact name of Registrant as specified in its charter)
Delaware 51-0354675
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
One Bowdoin Square, Boston, Massachusetts 02114
(Address of principal executive offices, including zip code)
(617) 788-3000
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12 (b) OR 12 (g)OF THE ACT:
None
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No __
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. X
As of March 29, 2000, there were 10 shares of common stock of Selkirk
Cogen Funding Corporation, $1 par value outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
None
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TABLE OF CONTENTS
Page
PART I
Item 1. Business..................................................... 3
Item 2. Properties................................................... 16
Item 3. Legal Proceedings............................................ 17
Item 4. Submission of Matters to a Vote of Security Holders.......... 18
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 19
Item 6. Selected Financial Data..................................... 19
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations....................... 20
Item 7A. Quantitative and Qualitative Disclosures About Market Risk .. 30
Item 8. Financial Statements and Supplementary Data.................. 31
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure....................... 31
PART III
Item 10. Directors and Executive Officers of the Funding Corporation
and the Managing General Partner.......................... 32
Item 11. Executive and Board Compensation and Benefits................ 34
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 34
Item 13. Certain Relationships and Related Transactions............... 35
PART IV
Item 14. Financial Statements, Exhibits and Reports on Form 8-K....... 36
Signatures............................................................ 49
2
PART I
ITEM 1. BUSINESS
General
Selkirk Cogen Partners, L.P. (the "Partnership") is a Delaware limited
partnership that owns a natural gas-fired cogeneration facility in the Town of
Bethlehem, County of Albany, New York (together with associated materials,
ancillary structures and related contractual and property interests, the
"Facility"). The Partnership was formed in 1989, and its sole business is the
ownership, operation and maintenance of the Facility. The Partnership has
long-term contracts to sell electric capacity and energy produced by the
Facility to Niagara Mohawk Power Corporation ("Niagara Mohawk") and Consolidated
Edison Company of New York, Inc. ("Con Edison") and steam produced by the
Facility to GE Plastics, a core business of General Electric Company ("General
Electric"). The Partnership operates as a single business segment.
Selkirk Cogen Funding Corporation (the "Funding Corporation"), a
Delaware corporation, was organized in April 1994 to serve as a single-purpose
financing subsidiary of the Partnership. All of the issued and outstanding
capital stock of the Funding Corporation is owned by the Partnership.
The Partnership and the Funding Corporation's principal executive
offices are located at One Bowdoin Square, Boston, Massachusetts 02114. The
telephone number is (617) 788-3000.
The Partnership
The managing general partner of the Partnership is JMC Selkirk, Inc.
("JMC Selkirk" or the "Managing General Partner"). The other general partner of
the Partnership (together with JMC Selkirk, the "General Partners") is RCM
Selkirk GP, Inc. ("RCM Selkirk GP", formerly Cogen Technologies Selkirk GP,
Inc.). The limited partners of the Partnership (the "Limited Partners," and
together with the General Partners, the "Partners") are JMC Selkirk, PentaGen
Investors, L.P. ("Investors", formerly JMCS I Investors, L.P.), EI Selkirk, Inc.
("EI Selkirk") and RCM Selkirk, LP, Inc. ("RCM Selkirk LP", formerly Cogen
Technologies Selkirk LP, Inc.).
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.
3
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, RCM Selkirk GP may assume the powers and
responsibilities of the Managing General Partner and of the Project Management
Firm. Under the Partnership Agreement, each General Partner other than the
Managing General Partner may convert its general partnership interest to that of
a Limited Partner.
JMC Selkirk is an indirect, wholly owned subsidiary of Beale Generating
Company ("Beale", formerly J. Makowski Company, Inc ("JMCI")) which is jointly
owned by Cogentrix Eastern America, Inc. ("Cogentrix") and PG&E Generating Power
Group, LLC ("PG&EGen Power"). Cogentrix is a subsidiary of Cogentrix Energy,
Inc. and PG&EGen Power is an indirect, wholly owned subsidiary of PG&E
Corporation.
JMCS I Management is an indirect, wholly-owned subsidiary of PG&E
Corporation.
Investors is a Delaware limited partnership consisting of JMCS I
Holdings, Inc., JMC Selkirk. (each an affiliate of Beale), and TPC Generating,
Inc.
RCM Selkirk GP and RCM Selkirk LP are each affiliates of RCM Holdings,
Inc. ("RCM", formerly Cogen Technologies, Inc.).
EI Selkirk is a wholly-owned subsidiary of GPU International, Inc.
("GPUI", formerly Energy Initiatives, Inc.) which is a wholly-owned subsidiary
of GPU, Inc.
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") 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 the financing of its outstanding
indebtedness and the remaining proceeds were loaned to the Partnership (the
total amount of such extensions of credit, the "Partnership Loans"). In November
1994, the Funding Corporation and the Partnership offered to exchange (i)
$165,000,000 of 8.65% First Mortgage Bonds Due 2007, Series A (the "New 2007
Bonds") for a like principal amount of Old 2007 Bonds, and (ii) $227,000,000 of
8.98% First Mortgage Bonds Due 2012, Series A (the "New 2012 Bonds," and
collectively with the New 2007 Bonds, the "New Bonds", and the New Bonds
together with the Old Bonds, the "Bonds") for a like principal amount of Old
2012 Bonds, respectively, with the holders thereof. On December 12, 1994, the
exchange of all of the Old
4
Bonds for the New Bonds was completed, and none of the Old Bonds remain
outstanding. The obligations of the Funding Corporation in respect of the Bonds
are unconditionally guaranteed by the Partnership (the "Guarantee").
The Bonds, the Partnership Loans and the Guarantee are not guaranteed
by, or otherwise obligations of, the Partners, Beale, TPC Generating, Inc., PG&E
Corporation, Cogentrix Energy, Inc., RCM, GPU, Inc., 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 RCM Selkirk 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, Con Edison and PG&E Energy Trading - Power,
L.P. 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").
5
Niagara Mohawk
The Partnership has a long term contract with Niagara Mohawk to sell
electric capacity and energy produced by Unit 1 to Niagara Mohawk. For the year
ended December 31, 1999, 1998 and 1997, electric sales to Niagara Mohawk
accounted for approximately 20.0%, 20.5% and 19.3%, respectively, of total
project revenues.
In 1996, the Partnership joined with generators which, like the
Partnership, are not regulated as utilities ("non-utility generators") selling
power to Niagara Mohawk to commence negotiations concerning a joint settlement
that would result in the termination or restructuring of their respective power
purchase agreements. The Partnership entered into a Master Restructuring
Agreement (as amended on March 31, 1998, April 21, 1998, May 7, 1998 and June 2,
1998, the "MRA") dated July 9, 1997 among Niagara Mohawk, the Partnership and
certain other non-utility power generators selling electricity to Niagara Mohawk
(the "Settling IPP's").
The closing of the transactions provided under the MRA for the Settling
IPP's (other than the Partnership) occurred on June 30, 1998 (the "Other
Settling IPP Closing"). At the Other Settling IPP Closing, the Partnership made
$2.2 million in payments related to the agreed allocation among the Settling
IPP's of certain costs and benefits. The closing of the MRA transactions between
the Partnership and Niagara Mohawk occurred on August 31, 1998. At that time,
the Amended and Restated Power Purchase Agreement, dated as of July 1, 1998,
between the Partnership and Niagara Mohawk became effective (the "Amended and
Restated Niagara Mohawk Power Purchase Agreement"), and Niagara Mohawk made cash
payments of approximately $10.3 million, representing its net share of the
agreed allocation among IPP's for certain adjustments, into the Partnership's
Project Revenue Fund maintained at Bankers Trust Company, as Depositary Agent
under the May 1, 1994 Deposit and Disbursement Agreement. In addition, the
Partnership delivered notices to Paramount Resources Limited ("Paramount") and
TransCanada Pipelines Limited ("TransCanada") that the Second Amended and
Restated Gas Purchase Contract, dated as of May 6, 1998, between the Partnership
and Paramount, and the Amending Agreement to Gas Transportation Contract, dated
as of July 20, 1998, between the Partnership and TransCanada had become
effective.
On August 31, 1998, the Partnership received written notice from
Standard & Poor's Corporation ("S&P") that, after giving effect to the
consummation of the transactions contemplated by the Amended and Restated
Niagara Mohawk Power Purchase Agreement, S&P affirmed its "BBB-" rating of the
Bonds and removed the rating from CreditWatch. On August 27, 1998, the
Partnership received written notice from Moody's Investors Service, Inc.
("Moody's") that, after giving effect to the Unit 1 Restructuring, Moody's
affirmed its "Baa3" rating of the Bonds, changed the outlook of the New 2007
Bonds from "negative" to "stable" and did not change its previous "negative
outlook" with respect to the New 2012 Bonds. As of the date of this report,
neither S&P nor Moody's has made any changes to the ratings of the Bonds.
6
Unit 1 commenced commercial operation on April 17, 1992 and through
June 30, 1998 sold at least 79.9 MW of electric capacity and associated energy
to Niagara Mohawk under the original long-term contract that allowed Niagara
Mohawk to schedule Unit 1 for dispatch on an economic basis (the "Original
Niagara Mohawk Power Purchase Agreement"). The term of the Original Niagara
Mohawk Power Purchase Agreement was 20 years from the date of initial commercial
operation of Unit 1. On August 31, 1998 the Partnership and Niagara Mohawk
executed an Amended and Restated Niagara Mohawk Power Purchase Agreement in
conjunction with the consummation of the transactions pursuant to the MRA. The
term of the Amended and Restated Niagara Mohawk Power Purchase Agreement is ten
years from July 1, 1998 with the exception of Niagara Mohawk's transitional call
rights discussed below.
The Amended and Restated Niagara Mohawk Power Purchase Agreement
provides for a monthly contract payment ("Monthly Contract Payment") which is
comprised of four indexed pricing components:(i) a capacity payment, (ii) an
energy payment, (iii) a transportation payment, and (iv) an operation and
maintenance payment. The capacity payment, transportation payment, operation and
maintenance payment and a fixed portion of the energy payment are payable
whether or not the Partnership sells energy or capacity to Niagara Mohawk. The
variable portion of the energy payment varies with the quantities of energy and
capacity actually sold to Niagara Mohawk pursuant to the Sale Option, Call
Option or exercise by Niagara Mohawk of its right of first refusal (Sale Option
and Call Option are defined below). Niagara Mohawk will be obligated to pay the
Partnership the Monthly Contract Payment to the extent such number is positive,
and, the Partnership will be obligated to pay Niagara Mohawk the Monthly
Contract Payment to the extent such number is negative. Since the capacity
payment and the fixed portion of the energy payment are offset by actual market
prices, during periods in which the market energy price or market capacity price
is high, the sum of these payments could result in a negative number. In such
event the Partnership would be obligated to make payments to Niagara Mohawk.
Under the Amended and Restated Niagara Mohawk Power Purchase Agreement, the
Partnership at all times retains the right to sell Unit 1 energy and associated
capacity at the prevailing market price (assuming the plant is available for
generation). The Partnership would expect net revenues from such sales to
mitigate the impact of any payments it might be required to make to Niagara
Mohawk during periods in which actual market prices are high.
During the period from July 1, 1998 through November 18, 1999, the
initial market pricing for energy was a proxy market price based on Niagara
Mohawk's tariff for power purchases from Qualifying Facilities. During this
period, Niagara Mohawk also had the right ("Call Option") to call Unit 1's
energy and capacity, up to the defined contract quantities. If Niagara Mohawk
chose to exercise its Call Option, the Partnership had the right to sell and
deliver, and Niagara Mohawk had the obligation to take and pay for, all energy
produced by Unit 1 which exceeded the Call Option quantity ("Excess Energy").
The price Niagara Mohawk was required to pay for the Call Option quantity and
the Excess Energy was the higher of (a) the initial market energy rate, or (b)
the Partnership's variable gas opportunity costs and operation and maintenance
costs ("Variable Energy Price"). Niagara Mohawk did not exercise its Call
Option. On November 18, 1999, the New York Independent System
7
Operator ("ISO") commenced operations for each of eleven regions and at each
generator interconnection within New York State. The ISO establishes a
marketplace whereby market prices will be determined based on daily bids for
quantity and price of energy as put by each willing supplier and will establish
the price at which each generator will be paid for energy supplied to the
region.
Niagara Mohawk has a right of first refusal to purchase energy and/or
capacity up to the applicable monthly contract quantity during the ten-year term
of the Amended and Restated Niagara Mohawk Power Purchase Agreement.
Accordingly, before the Partnership may sell such energy and associated capacity
to third parties, it must first offer Niagara Mohawk the opportunity to purchase
that energy and capacity at the market energy price, and, if applicable, the
market capacity price. If Niagara Mohawk declines, the Partnership may sell such
power to third parties. Energy and associated capacity in excess of the monthly
contract quantity is not subject to Niagara Mohawk's right of first refusal.
During the period from July 1, 1998 through November 18, 1999, the
Partnership had the option to sell and deliver energy and capacity to Niagara
Mohawk up to a specified monthly contract quantity, plus up to 5% of the monthly
contract quantity ("Sale Option"). Niagara Mohawk was required to take and pay
for such energy and capacity as the Partnership delivered to it under the Sale
Option at the market energy price, and, if applicable, the market capacity
price. This energy and capacity could be produced by Unit 1, Unit 2 or a third
party source. The Partnership continues to have the ability under the Amended
and Restated Niagara Mohawk Power Purchase Agreement to augment the fixed
portions of the Monthly Contract Payment by selling such energy and associated
capacity to third parties, provided that it first offers Niagara Mohawk the
opportunity to purchase that energy and capacity at the market energy price,
and, if applicable, the market capacity price and Niagara Mohawk declines.
The annual contract volumes and notional contract quantities which are
used to calculate the fixed portions of the Monthly Contract Payment and
establish the maximum quantities of energy and capacity which Niagara Mohawk is
obligated to purchase or the Partnership is obligated to sell are set forth
below.
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Annual Contract
Contract Volume Quantity
Year MWh MW
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1 325,400 37.146
2 331,000 37.785
3 375,900 42.911
4 417,500 47.660
5 419,500 47.888
6 442,000 50.457
7 451,700 51.564
8 461,300 52.660
9 473,400 54.041
10 485,200 55.388
- ----------------------------------------------------------------------------
8
Niagara Mohawk owns, operates and maintains interconnection facilities
for the combined Facility in accordance with separate Unit 1 and Unit 2
interconnection agreements. The Unit 1 interconnection facility is necessary to
effect the transfer of electricity produced at Unit 1 into Niagara Mohawk's
power grid at the delivery point adjacent to Unit 1. Since Unit 1 is
interconnected directly to Niagara Mohawk's power grid, no transmission services
are required for the delivery of power under the Amended and Restated Niagara
Mohawk Power Purchase Agreement. The Unit 2 interconnection facility is
necessary to effect the transfer of electricity produced at Unit 2 into Niagara
Mohawk's transmission system. Pursuant to a transmission services agreement,
Niagara Mohawk has agreed to provide firm transmission services from Unit 2 to
the point of interconnection between Niagara Mohawk's transmission system and
Con Edison's transmission system for a period of 20 years from the date of the
commencement of commercial operation of Unit 2.
Con Edison
Unit 2 commenced commercial operation on September 1, 1994 and is
selling 265 MW of electric capacity and associated energy to Con Edison under a
long-term contract that allows Con Edison to schedule Unit 2 for dispatch on an
economic basis (the "Con Edison Power Purchase Agreement," and together with the
Amended and Restated Niagara Mohawk Power Purchase Agreement, the "Power
Purchase Agreements"). The Con Edison Power Purchase Agreement has a term of 20
years from the date of commencement of commercial operation of Unit 2, subject
to a 10-year extension under certain conditions. The Con Edison Power Purchase
Agreement provides for four payment components:(i) a capacity payment, (ii) a
fuel payment, (iii) an Operations and Maintenance ("O&M") payment and (iv) a
wheeling payment. The capacity payment, a portion of the fuel payment, a portion
of the O&M payment, and the wheeling payment are fixed charges to be paid on the
basis of plant availability to operate whether or not Unit 2 is dispatched
on-line. The variable portions of the fuel payment and O&M payment are payable
based on the amount of electricity produced by Unit 2 and delivered to Con
Edison. The total fixed and variable fuel payment is capped at a ceiling price
established (and is subject to adjustment) in accordance with the Con Edison
Power Purchase Agreement, and includes a component, which is equal to one-half
of the amount by which Unit 2's actual fixed and variable fuel commodity and
transportation costs differs from the ceiling price. For the year ended December
31, 1999, 1998 and 1997 electric sales to Con Edison accounted for approximately
69.8%, 74.0% and 72.4%, respectively, of total project revenues.
In 1994 and 1995 Con Edison claimed the right to acquire that portion
of Unit 2's firm natural gas supply not used in operating Unit 2, when Unit 2 is
dispatched off-line or at less than full capability ("non-plant gas"), or
alternatively to be compensated for 100% of the margins derived from non-plant
gas sales. The Con Edison Power Purchase Agreement contains no express language
granting Con Edison any rights with respect to such excess natural gas.
Nevertheless, Con Edison argued that, since payments under the contract include
fixed fuel charges which are payable whether or not Unit 2 is dispatched
on-line, Con Edison is entitled to exercise such rights. The Partnership
vigorously disputes the position adopted by Con Edison, and since the
commencement of Unit 2's operation in 1994, the Partnership has
9
made and continues to make, from time to time, non-plant gas sales from Unit 2's
gas supply. Although representatives of Con Edison have expressly reserved all
rights that Con Edison may have to pursue its asserted claim with respect to
non-plant gas sales, the Partnership has received no further formal
communication from Con Edison on this subject since 1995. In the event Con
Edison were to pursue its asserted claim, the Partnership would expect to pursue
all available legal remedies, but there can be no certainty that the outcome of
such remedial action would be favorable to the Partnership or, if favorable,
would provide for the Partnership's full recovery of its damages. The
Partnership's cash flows from the sale of electric output would be materially
and adversely affected if Con Edison were to prevail in its claim to Unit 2's
excess natural gas volumes and the related margins.
On July 21, 1998, the NYPSC approved a plan submitted by Con Edison for
the divestiture of certain of its generating assets (the "Con Edison Divestiture
Plan"). Although the Con Edison Divestiture Plan does not include any proposal
by Con Edison for the sale or other disposition of its contractual obligations
for purchasing power from non-utility generators, like the Partnership, the
NYPSC has ordered Con Edison to submit a report regarding the feasibility of
divesting its non-utility generator entitlements. At this time, the Partnership
has insufficient information to determine whether, in the course of these
proceedings at the NYPSC, Con Edison may seek to assign its rights and
obligations under the Con Edison Power Purchase Agreement with the Partnership
to a third party or to take some other action for the purpose of divesting
itself of the power purchase obligations under such contract; nor can the
Partnership evaluate the impact which any such assignment or other action, if
proposed, may ultimately have on the Con Edison Power Purchase Agreement.
PG&E Energy Trading - Power, L.P.
To sell the excess capacity and energy generated from Units 1 and 2 and
other energy-related products, the Partnership entered into an enabling
agreement (the "Enabling Agreement") with PG&E Energy Trading - Power, L.P.
("PG&E Energy Trading"), an affiliate of JMC Selkirk. The Enabling Agreement
became effective on May 31, 1996, for a term of one year, and may be extended by
mutual agreement of the Partnership and PG&E Energy Trading. The Enabling
Agreement has previously been extended through May 31, 2000 and the Partnership
intends to renew the Enabling Agreement through May 2001. Under the Enabling
Agreement, the Partnership has the ability to enter into certain transactions
for the purchase and sale of electric capacity, electric energy and other
services at negotiated market prices. For each transaction, a transaction letter
is executed establishing the following terms and conditions: (i) the period of
delivery; (ii) the contract price; (iii) the delivery points; and (iv) the
contract quantity. For the year ended December 31, 1999, 1998 and 1997, sales to
PG&E Energy Trading accounted for approximately 3.4%, 1.2% and 0.1%,
respectively, of total project revenues.
General Electric
Pursuant to a steam sales agreement with General Electric (the "Steam
Sales Agreement"), the Partnership is obligated to sell up to 400,000 lbs/hr of
the thermal output of
10
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 reduced the quantity of steam required by the GE Plant. Under the
energy efficiency project, General Electric anticipates managing its annual
average steam demand at 160,000 lbs/hr. If General Electric is able to manage
its annual average steam demand at 160,000 lbs/hr then the Partnership's steam
revenues would be reduced to the nominal amount General Electric is charged for
the annual equivalent of 160,000 lbs/hr. 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. For the year ended December 31, 1999, 1998 and 1997, sales to General
Electric accounted for approximately 0.5%, 0.0% and 0.3%, respectively, of total
project revenues.
Unit 1 Gas Supply and Transportation
To supply natural gas needed to operate Unit 1, the Partnership entered
into a gas supply agreement with Paramount Resources Ltd. ("Paramount") on a
firm 365-day per year basis for a 15-year term beginning November 1, 1992 (the
"Original Paramount Contract"). On May 6, 1998, the Partnership and Paramount
executed a Second Amended and Restated Gas Purchase Contract (the "Amended
Paramount Contract") in conjunction with consummation of the transactions
pursuant to the MRA. Under the Amended Paramount Contract, the 15-year term
remained unchanged and the following key volume, price and dedicated reserve
terms (among others) have been modified as follows: (i) the maximum daily
quantity of natural gas which the Partnership is entitled to purchase has been
reduced from 23,000 Mcf to 16,400 Mcf; (ii) the commodity charge component of
the contract price is no longer a base price escalated with Niagara Mohawk's
fossil fuel index but instead reflects the current Empress spot price (the same
indexed price as is used to determine the fixed portion of the Energy Payment
under the Amended and Restated Niagara Mohawk Power Purchase Agreement); (iii)
the gas price renegotiation/arbitration provisions in the existing Paramount
Contract have been eliminated; (iv) Paramount has increased flexibility to
manage the reserves dedicated to the Amended Paramount Contract so long as
Paramount is meeting its delivery obligations for the volumes nominated by the
Partnership; and (v) on any day on which Paramount fails to meet its delivery
obligations for Partnership nominations, Paramount is obligated to make its
transportation on NOVA Corporation of Alberta available to the Partnership to
the extent of the shortfall. The Amended Paramount Contract requires
11
Paramount to maintain a level of recoverable reserves and deliverability from
its dedicated reserves through the term of the Amended Paramount Contract.
Paramount must demonstrate that it meets the recoverable reserves and
deliverability requirements in an annual report to the Partnership.
The Partnership entered into certain long-term contracts (collectively,
the "Unit 1 Gas Transportation Contracts") for the transportation of the Unit 1
natural gas volumes on a firm 365-day per year basis with TransCanada Pipelines
Limited ("TransCanada"), Iroquois Gas Transmissions System, L.P. ("Iroquois")
and Tennessee Gas Pipeline Company ("Tennessee"). Each of the Unit 1 Gas
Transportation Contracts has a term of 20 years beginning November 1, 1992.
Concurrent with the effectiveness of the Amended Paramount Contract, the
Partnership released 6,000 Mcf of the Partnership's daily transportation
capacity rights under the Partnership's firm gas transportation contract for
Unit 1 with TransCanada, in conjunction with Paramount's acquiring 6,000 Mcf of
daily transportation capacity rights on TransCanada's pipeline system.
Unit 2 Gas Supply and Transportation
To supply natural gas needed to operate Unit 2, the Partnership entered
into gas supply agreements with Imperial Oil Resources, PanCanadian Petroleum
Limited and Producers Marketing Ltd. (formerly Atcor Limited) (collectively, the
"Unit 2 Gas Supply Contracts"), each on a firm 365-day per year basis. Each of
the Unit 2 Gas Supply Contracts has a 15-year term beginning November 1, 1994.
The Unit 2 gas suppliers have supported their delivery obligations to the
Partnership with their respective corporate warranties. The Unit 2 Gas Supply
Contracts are not supported by dedicated reserves. The Partnership entered into
certain long-term contracts (collectively, the "Unit 2 Gas Transportation
Contracts") for the transportation of the Unit 2 natural gas volumes on a firm
365-day per year basis with TransCanada, Iroquois and Tennessee. Each of the
Unit 2 Gas Transportation Contracts has a term of 20 years beginning November 1,
1994.
Fuel Management
The Partnership, through the Project Management Firm, manages the
Facility's fuel arrangements. The Partnership attempts to direct the supply and
transportation of natural gas to Unit 1 and Unit 2 under its long-term gas
supply and transportation contracts so as to have sufficient quantities of
natural gas available at the Facility to meet its scheduled operation. In
addition, the Partnership endeavors to take advantage of market opportunities,
as available, to resell its long-term, firm natural gas volumes at favorable
prices relative to their costs and relative to the cost of substitute fuels.
These opportunities include resales of excess natural gas supplies ("gas
resales") when Unit 1 or Unit 2 is dispatched off-line or at less than full
capacity, and "peak shaving" arrangements whereby the Partnership grants to
local distribution companies or other purchasers a call on a specified portion
of the Partnership's firm natural gas supply for a specified number of days
during the winter season. At such times as the purchaser calls upon the
Partnership's firm natural gas supply under a peak
12
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.
Unit 1 and Unit 2 have the capability to operate on No. 2 fuel oil and
are able to switch fuel sources from natural gas to fuel oil, and back, without
interrupting the generation of electricity. The Partnership's air permit allows
the Facility to burn oil for a maximum of 2,190 hours per year (91.25 days per
year) at full capacity. The Partnership currently has on-site storage for
approximately one million gallons of fuel oil, a supply sufficient to run all
three gas turbines constituting the Facility for approximately one and a half
days at full capacity without refilling. The Partnership purchases fuel oil on a
spot basis. The Facility Site is approximately five miles from the Port of
Albany, New York, a major oil terminal area. In addition, several major oil
companies supply No. 2 fuel oil in the Albany area through leased storage or
throughput arrangements. Fuel oil is transported to the Facility by truck.
Customers/Competition
Niagara Mohawk is an investor-owned utility engaged in the production,
transmission and distribution of electrical energy and natural gas to customers
in upstate New York.
Con Edison is an investor-owned utility engaged in the production,
transmission and distribution of electrical energy and natural gas to New York
City (except portions of Queens) and most of Westchester County, New York.
PG&E Energy Trading, an affiliate of JMC Selkirk, is a wholly-owned
indirect subsidiary of PG&E Corporation, engaged in selling energy and
energy-related products to power marketers, industrials, utilities and
municipalities. PG&E Energy Trading trades with United States and Canadian
counterparties.
GE Plastics, a core business of General Electric, manufactures
high-performance engineered plastics used in applications such as automobiles,
housings for computers and other business equipment. GE Plastics sells worldwide
to a diverse customer base consisting mainly of manufacturers.
13
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 a long-term agreement
to sell electric generating capacity and energy from the Facility to Con Edison.
The Partnership has also executed an Amended and Restated Power Purchase
Agreement with Niagara Mohawk, which now provides a hedge on energy costs to
Niagara Mohawk while also providing for recovery of capacity and other fixed
payments over a term of ten years. Therefore, the Partnership does not expect
competitive forces to have a significant effect on this portion of its business.
Nevertheless, under each of these agreements the Facility will typically be
scheduled on an economic basis, which takes into account the variable cost of
electricity to be delivered by the Unit compared to the variable cost of
electricity available to the purchaser from other sources. Accordingly,
competitive forces may have some effect on the Facility's dispatch levels. The
Partnership cannot, at this time, determine what long-term effect, if any, the
impact of such competitive sales will have on the Partnership's financial
condition or results of operation. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations" for a discussion of
the Facility's dispatch levels.
Seasonality
The Partnership's reliance on its power producer's customer and market
demand results in the Facility's dispatch being somewhat affected by
seasonality. Niagara Mohawk's residential customer demand peaks during the
colder winter months due to customer reliance on electric heat, and Con Edison's
commercial customer demand peaks during the warmer summer months due to customer
reliance on air conditioning in office buildings. In addition, the gas resale
market is also somewhat seasonal in nature, with the cold winter months tending
to drive up the price of natural gas.
Regulations and Environmental Matters
The Partnership must sell an aggregate annual average of approximately
80,000 lbs/hr from Unit 1 and Unit 2 combined for use as process steam by
General Electric and must satisfy other operating and ownership criteria in
order to comply with the requirements for a Qualifying Facility under PURPA. If
the Facility were to fail to meet such criteria, the Partnership may become
subject to regulation as a subsidiary of a holding company, a public
14
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.
All regulatory approvals currently required to operate the combined
Facility have been obtained. The Partnership is subject to federal, state, and
local laws and regulations pertaining to air and water quality, and other
environmental matters. In response to regulatory change, and in the course of
normal business, the Partnership files requisite documents and applies for a
variety of permits, modifications, renewals and regulatory extensions. It is not
possible to ascertain with certainty when or if the various required
governmental approvals and actions which are petitioned will be accomplished,
whether modifications of the Facility will be required or, generally, what
effect existing or future statutory action may have upon Partnership operations.
The 1990 amendments to the Federal Clean Air Act (the "1990 Clean Air
Amendments") require a large number of rulemaking and other actions by the
United States Environmental Protection Agency (the "EPA" or the "Agency") and
the New York State Department of Environmental Conservation (the "DEC"). The DEC
has adopted regulations for New York State's (the "State") operating permit
program consistent with the requirements of Title V of the 1990 Clean Air Act
Amendments and has received interim final approval of the State's program from
the EPA. Pursuant to the State's program the Facility is required to obtain a
new operating permit, an application for which was submitted to the DEC prior to
June 9, 1997. Except as set forth herein below, no material proceedings have
been commenced or, to the knowledge of the Partnership, are contemplated by any
federal, state or local agency against the Partnership, nor is the Partnership a
defendant in any litigation with respect to any matter relating to the
protection of the environment.
15
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.
Employees
The Partnership has no employees. The Project Management Firm provides
overall management and administration services to the Partnership pursuant to a
Project Administrative Services Agreement. The Project Management Firm provides
ten site employees and support personnel in its Boston, Massachusetts and
Bethesda, Maryland offices, who manage Unit 1 and Unit 2 on a combined basis.
General Electric through its O&M Services component (the "Operator")
provides operation and maintenance services for the Facility pursuant to an
Amended and Restated Operation and Maintenance Agreement between the Partnership
and General Electric (the "O&M Agreement"). The Operator has substantial
experience in operating and maintaining generating facilities using combustion
turbine and combined cycle technology and provides 32 employees to operate the
Facility.
ITEM 2. PROPERTIES
The Facility is located in the Town of Bethlehem, County of Albany, New
York, on approximately 15.7 acres of land (the "Facility Site") which is leased
by the Partnership from General Electric. In addition, the Partnership laterally
owns an approximately 2.1 mile pipeline which is used for the transportation of
natural gas from a point of interconnection with Tennessee's pipeline facilities
to the Facility Site. General Electric has granted certain permanent easements
for the location of certain of the Unit 1 and Unit 2 interconnection facilities
and other structures.
The Partnership has leased the Facility to the Town of Bethlehem
Industrial Development Agency (the "IDA") pursuant to a facility lease
agreement. The IDA has leased the Facility back to the Partnership pursuant to a
sublease agreement. The IDA's participation 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.
16
ITEM 3. LEGAL PROCEEDINGS
The Partnership is party to the legal proceedings described below.
Gas Transportation Proceedings
As part of the ordinary course of business, the Partnership routinely
files complaints and intervenes in rate proceedings filed with the FERC by its
gas transporters, as well as related proceedings.
During the fourth quarter of 1999, the Partnership converted its
Tennessee gas transportation service for Unit 1 to a more flexible service.
Prior to such conversion, the Partnership could not use such capacity freely for
secondary purposes. The conversion option was not available until tariff changes
made by Tennessee became effective during the fourth quarter of 1999. The new
flexibility will allow the Partnership to utilize alternate receipt and delivery
points, segment the capacity and release the capacity to third parties.
In November 1996, Iroquois filed a rate case at the FERC proposing a
minor rate reduction. The 1996 rate case led to many issues which were at
various stages of appeal including an issue related to legal defense cost
recovery by Iroquois and other rate issues that were appealed by the parties
including the Partnership. The legal defense cost issues, the other rate issues
on appeal and going forward rate reductions were all negotiated as part of a
combined settlement. The settlement reached during 1999 and approved by the FERC
in February 2000 eliminates any recovery by Iroquois for its legal defense
costs, settles all pending appeals by all the parties and provides for an
overall cumulative rate reduction of $.048 per Dth over a four year moratorium.
Electric Transmission Proceedings
The Partnership is an intervenor in a proceeding initiated by certain
transmission owning New York utilities (the "Member Systems"), including Niagara
Mohawk, before the FERC. In this proceeding, the Member Systems, among other
things, seek to impose on transmission customers such as the Partnership
congestion charges arising from transactions that are scheduled less than a day
ahead ("intra-day nominations"). The Partnership's transmission services
agreement for Unit 2 with Niagara Mohawk (the "Transmission Services Agreement")
has been "grandfathered" in accordance with certain orders of the FERC and thus
is not generally governed by the terms of the Open Access Transmission Tariff of
the New York Independent System Operator ("NYISO OATT"). Thus, for example, the
Partnership is exempt from congestion charges arising from transactions
undertaken in the day-ahead market. The Partnership contends that its
Transmission Services Agreement is similarly grandfathered with respect to
intra-day nominations, and that the position of the Member Systems is
inconsistent with the Partnership's Transmission Services Agreement, the FERC's
orders relating to grandfathered transactions, and other established FERC
precedent, as well as the Con Edison Power Purchase Agreement. It is not
possible to determine at this point in the proceeding the Partnership's
likelihood of success or the effect that an adverse
17
decision would have on the Partnership. The Partnership has entered into a
settlement with the Member Systems on all other matters raised in the
proceeding.
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 curtailment proceedings and directed an administrative law
judge to prepare a recommended decision under an abbreviated deadline. On March
18, 1998, the NYPSC announced that an order instituting a curtailment policy
would be forthcoming, however, a written order has not yet been issued. In
conjunction with the execution of the Amended and Restated Niagara Mohawk Power
Purchase Agreement on August 21, 1998, Niagara Mohawk waived any rights to
curtail purchases from the Partnership.
With respect to the Con Edison petition, the Partnership has taken the
position in this proceeding that it should not be subject to curtailment as a
result of this proceeding, even if the NYPSC grants Con Edison some measure of
generic curtailment rights. The Partnership's position is based in part on the
fact that Con Edison did not bargain for an express curtailment right in its
Power Purchase Agreement and the Partnership agreed to permit Con Edison to
direct the dispatch of Unit 2. Nevertheless, Con Edison has refused to expressly
waive its claimed curtailment rights against dispatchable facilities and has not
agreed to exempt the Facility from curtailment, notwithstanding the absence of
contractual language in the Power Purchase Agreement granting the utility this
right. If Con Edison were to receive NYPSC authorization to curtail power
purchases from Qualifying Facilities including dispatchable facilities, it may
seek to implement curtailment with respect to the Partnership by avoiding not
only energy payments but also capacity payments during periods in which the
Facility is curtailed. Such a reduction in energy payments and capacity payments
could materially and adversely affect the Partnership's net operating revenues.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
18
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 ten issued and outstanding shares of common stock of Funding
Corporation, $1.00 par value per share, are owned by the Partnership. All of the
common equity interests of the Partnership are held by the Partners and,
therefore, there is no established public market for the Partnership's common
equity interests.
ITEM 6. SELECTED FINANCIAL DATA
Unit 1 and Unit 2 began commercial operations on April 17, 1992 and
September 1, 1994, respectively. The selected financial data set forth below
should be read in conjunction with the financial statements, related notes and
other financial information included elsewhere herein.
Year Ended December 31,
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
(in thousands)
Statement of Operations
Data:
Operating revenues $173,057 $165,986 $171,583 $174,442 $155,778
Cost of revenues 112,920 112,487 121,305 119,747 114,491
Operating expenses 4,553 5,130 6,584 6,669 7,174
Operating income 55,584 48,369 43,694 48,026 34,113
Net interest expense 31,687 32,048 32,234 32,844 32,392
--------- --------- ---------- --------- ---------
Net income $ 23,897 $ 16,321 $ 11,460 $ 15,182 $ 1,721
========= ========= ========== ========= =========
December 31,
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
(in thousands)
Balance Sheet Data:
Plant and equipment, net $297,034 $308,999 $321,537 $334,229 $346,285
Total assets 367,087 373,877 385,874 401,454 416,080
Long-term bonds,
net of current portion 373,826 381,133 385,955 389,253 391,420
Partners' deficits (50,832) (46,810) (32,282) (18,810) 1,530
19
Supplementary Financial Information
The following is a summary of the quarterly results of operations for
the years ended December 31, 1997, December 31, 1998 and December 31, 1999.
Three Months Ended (unaudited)
---------------------------------------------------------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
(in thousands)
Year Ended
December 31, 1997
- --------------------
Operating revenues $ 43,925 $ 40,850 $ 42,386 $44,422
Gross Profit 12,634 11,726 12,883 13,035
Net income 2,844 1,986 2,968 3,662
Year Ended
December 31, 1998
- --------------------
Operating revenues $ 41,409 $ 41,117 $ 43,421 $40,039
Gross Profit 13,301 12,347 15,986 11,865
Net income 3,722 2,792 7,430 2,377
Year Ended
December 31, 1999
- --------------------
Operating revenues $ 42,323 $ 40,964 $ 46,503 $43,267
Gross Profit 17,218 11,182 17,204 14,533
Net income 8,196 2,003 8,088 5,610
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 $23.9 million,
$16.3 million and $11.5 million in 1999, 1998 and 1997, respectively, and made
cash distributions to the partners of approximately $27.9 million, $30.8 million
and $24.9 million, respectively.
New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities," (as amended by SFAS No. 137). SFAS No. 133
establishes accounting
20
and reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. SFAS No.
133 is effective for the Partnership's fiscal years beginning on January 1,
2001. Management has not completed an evaluation of the impact on the
Partnership's consolidated financial statements of adopting this new standard
(see Note 2 to the consolidated financial statements).
Results of Operations
Year Ended December 31, 1999 Compared to the Year Ended December 31, 1998
The Partnership earned net income of approximately $23.9 million for
the year ended December 31, 1999 as compared to net income of approximately
$16.3 million for the prior year. The $7.6 million increase in net income is
primarily due to increases in electric revenues from Unit 1 and gas resale
revenues.
Total revenues for the year ended December 31, 1999 were approximately
$173.1 million as compared to approximately $166.0 million for the prior year.
Electric Revenues (dollars and kWh's in millions):
For the Year Ended
December 31, 1999 December 31, 1998
------------------------------------- -------------------------------------
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ----- -------- --------
Unit 1 40.1 510.7 74.67% 85.56% 35.8 472.0 67.62% 74.60%
Unit 2 121.2 1,752.1 75.28% 81.37% 123.0 2,040.6 87.89% 91.74%
The "capacity factor" of Unit 1 and Unit 2 is the amount of energy
produced by each Unit in a given time period expressed as a percentage of the
total contract capability amount of potential energy production in that time
period.
The "dispatch factor" of Unit 1 and Unit 2 is the number of hours
scheduled for electric delivery (regardless of output level) in a given time
period expressed as a percentage of the total number of hours in that time
period.
Revenues from Unit 1 increased approximately $4.3 million for the year
ended December 31, 1999 as compared to the prior year. During the year ended
December 31, 1999, revenues from Niagara Mohawk and PG&E Energy Trading were
approximately $34.6 million and $5.5 million as compared to approximately $34.0
million and $1.8 million, respectively, for the prior year. The increase in
revenues from Unit 1 for the year ended December 31, 1999 was primarily due to
the increase in delivered energy as evidenced by the increase in the capacity
factors from 67.62% to 74.67%, and improved contract pricing resulting from the
Amended and Restated Niagara Mohawk Power Purchase Agreement. During the year
ended December 31, 1999, with the exception of April and October, the
Partnership received Monthly Contract Payments and delivered energy up to the
monthly
21
contract quantity to Niagara Mohawk. During the period from January 1, 1999
through November 17, 1999 contract energy delivered to Niagara Mohawk was sold
at a proxy market price based on Niagara Mohawk's tariff for power purchases
from Qualifying Facilities. Commencing on November 18, 1999, contract energy
delivered to Niagara Mohawk was sold at market prices established by the ISO.
See "Item 1. Business, The Facility and Certain Project Contracts" for a
discussion of the Amended and Restated Niagara Mohawk Power Purchase Agreement.
During the month of January 1999, the Partnership sold all of the Excess Energy
generated from Unit 1 to Niagara Mohawk. During the months of February, March,
June and September 1999, the Partnership sold all of the Excess Energy generated
from Unit 1 to PG&E Energy Trading. During the months of April, May, July,
August, November and December 1999, the Partnership sold Excess Energy from Unit
1 to both Niagara Mohawk and PG&E Energy Trading. During the month of October
1999, the Partnership did not sell any energy from Unit 1. Excess Energy
delivered to Niagara Mohawk and PG&E Energy Trading was sold at negotiated
market prices. Amortized deferred revenues of approximately $0.7 million are
also included in revenues from Niagara Mohawk for the year ended December 31,
1999.
During the eight months ended August 31, 1998, with the exception of
March and April, Niagara Mohawk dispatched Unit 1 on-line. Energy delivered
during the majority of January and the entire month of February was sold at full
contract rates. Energy delivered during the first four days of January, and the
entire months of May and June, was sold under special dispatch arrangements
which called for the pricing of delivered energy at variable rates which were
less than full contract rates. Had the Partnership not entered into special
dispatch arrangements, the Unit would have otherwise been dispatched off-line
during the relevant periods. During the six months ended December 31, 1998, with
the exception of October, the Partnership received Monthly Contract Payments and
delivered energy up to the monthly contract quantity to Niagara Mohawk. During
the six months ended December 31, 1998, contract energy delivered to Niagara
Mohawk was sold at a proxy market price based on Niagara Mohawk's tariff for
power purchases from Qualifying Facilities. During the month of October 1998,
Niagara Mohawk was not required to make a Monthly Contract Payment and the
Partnership sold all of the generated energy from Unit 1 to PG&E Energy Trading.
During the months of July, August and September 1998, the Partnership sold all
of the Excess Energy generated from Unit 1 to Niagara Mohawk. During the months
of November and December 1998, the Partnership sold all of the Excess Energy
generated from Unit 1 to PG&E Energy Trading. Energy delivered to PG&E Energy
Trading was sold at negotiated market prices. Amortized deferred revenues of
approximately $0.3 million are also included in revenues from Niagara Mohawk for
the year ended December 31, 1998.
Revenues from Unit 2 decreased approximately $1.8 million for the year
ended December 31, 1999 as compared to the prior year. During the year ended
December 31, 1999, revenues from Con Edison and PG&E Energy Trading were
approximately $120.9 million and $0.3 million as compared to approximately
$122.8 million and $0.2 million, respectively, for the prior year. The decrease
in revenues from Unit 2 for the year ended December 31, 1999 was primarily due
to the decrease in delivered energy as evidenced by the decrease in the capacity
factors from 87.89% to 75.28%. During the year ended December 31, 1999, revenues
22
from PG&E Energy Trading resulted from the sale of other energy-related
products. During the year ended December 31, 1998, revenues from PG&E Energy
Trading resulted from sales of generated capacity and energy in excess of
contract amounts due under the Con Edison Power Purchase Agreement.
Steam revenues for the year ended December 31, 1999 of approximately
$1.1 million were reduced by a reserve of approximately $0.3 million to reflect
the annual true-up so that General Electric would be charged a nominal amount
which is the annual equivalent of 160,000 lbs/hr. Steam revenues for the year
ended December 31, 1998 of approximately $0.5 million were reduced by a reserve
of the same amount to reflect the annual true-up. Delivered steam for the year
ended December 31, 1999 was approximately 1.6 billion pounds as compared to
approximately 1.4 billion pounds in the prior year.
Gas resale revenues for the year ended December 31, 1999 were
approximately $10.9 million on sales of approximately 4.4 million MMBtu's as
compared to approximately $7.2 million on sales of approximately 3.2 million
MMBtu's for the prior year. The $3.7 million increase in gas resale revenues
during the year ended December 31, 1999 is primarily due to higher natural gas
resale prices and the lower dispatch of Unit 2, which resulted in higher volumes
of natural gas becoming available for resale at higher prices. The increase in
natural gas resale prices during the year ended December 31, 1999 generally
resulted from higher market pricing for both gas and oil as well as increased
demands for electric generation. Gas resales occur during periods when Units 1
and 2 are not operating at full capacity.
Fuel costs for the year ended December 31, 1999 were approximately
$82.8 million on purchases of approximately 27.8 million MMBtu's as compared to
approximately $82.4 million on purchases of approximately 28.2 million MMBtu's
for the prior year. The $0.4 million increase in the cost of fuel was primarily
due to the higher price of gas under the firm fuel contracts, partially offset
by the write-off of reserves of approximately $1.4 million for amounts no longer
in dispute with gas suppliers and transporters. The Partnership has foreign
currency swap agreements to hedge against future exchange rate fluctuations
under fuel transportation agreements which are denominated in Canadian dollars.
During the years ended December 31, 1999 and 1998, fuel costs were increased by
approximately $2.3 million and $2.5 million, respectively, as a result of the
currency swap agreements.
Other operating and maintenance expenses for the year ended December
31, 1999 of approximately $17.7 million were comparable to the prior year.
Total other operating expenses, excluding amortization of deferred
financing charges, for the year ended December 31, 1999 were approximately $3.4
million as compared to approximately $4.0 million for the prior year. The $0.6
million decrease in other operating expenses, excluding amortization of deferred
financing charges, was primarily due to lower general and administrative
expenses.
23
Amortization of deferred financing charges of approximately $1.2
million for the year ended December 31, 1999 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, 1999 was
approximately $31.7 million as compared to approximately $32.0 million for the
prior year. The decrease in net interest expense is primarily due to lower bond
interest expense resulting from the lower principal balance outstanding.
Year Ended December 31, 1998 Compared to the Year Ended December 31, 1997
The Partnership reported net income of approximately $16.3 million for
the year ended December 31, 1998 as compared to net income of approximately
$11.5 million for the prior year. The increase in net income is primarily due to
an increase in delivered energy to electric customers and lower fuel costs and
other operating expenses.
Total revenues for the year ended December 31, 1998 were approximately
$166.0 million as compared to approximately $171.6 million for the prior year.
Electric Revenues (dollars and kWh's in millions):
For the Year Ended
December 31, 1998 December 31, 1997
------------------------------------- -------------------------------------
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ----- -------- --------
Unit 1 35.8 472.0 67.62% 74.60% 33.1 403.9 57.23% 62.61%
Unit 2 123.0 2,040.6 87.89% 91.74% 124.4 1,886.6 81.18% 89.89%
Revenues from Unit 1 increased approximately $2.7 million for the year
ended December 31, 1998 as compared to the prior year. During the year ended
December 31, 1998, revenues from Niagara Mohawk and PG&E Energy Trading were
approximately $34.0 million and $1.8 million, respectively. During the year
ended December 31, 1997, all revenues from Unit 1 were from Niagara Mohawk. The
increase in revenues from Unit 1 for the year ended December 31, 1998 was
primarily due to an increase in delivered energy as evidenced by the increase in
capacity factors from 57.23% to 67.62%, and improved contract pricing resulting
from the execution of the Amended and Restated Niagara Mohawk Power Purchase
Agreement on August 31, 1998 with terms and conditions retroactive to July 1,
1998. During the eight months ended August 31, 1998, with the exception of March
and April, Niagara Mohawk dispatched Unit 1 on-line. Energy delivered during the
majority of January and the entire month of February was sold at full contract
rates. Energy delivered during the first four days of January, and the entire
months of May and June, was sold under special dispatch arrangements which
called for the pricing of delivered energy at variable rates which were less
than full contract rates. Had the Partnership not entered into special dispatch
24
arrangements, the Unit would have otherwise been dispatched off-line during the
relevant periods. Effective August 31, 1998, in conjunction with the execution
of the Amended and Restated Niagara Mohawk Power Purchase Agreement, Niagara
Mohawk no longer has the right to direct the dispatch of Unit 1. See "Item 1.
Business, The Facility and Certain Project Contracts" for a discussion of the
Amended and Restated Niagara Mohawk Power Purchase Agreement. During the six
months ended December 31, 1998, with the exception of October, the Partnership
received Monthly Contract Payments and delivered energy up to the monthly
contract quantity to Niagara Mohawk. During the month of October 1998, Niagara
Mohawk was not required to make a Monthly Contract Payment and the Partnership
sold all of the generated energy from Unit 1 to PG&E Energy Trading. During the
months of July, August and September, 1998 the Partnership sold all of the
Excess Energy generated from Unit 1 to Niagara Mohawk. During the months of
November and December, 1998 the Partnership sold all of the Excess Energy
generated from Unit 1 to PG&E Energy Trading. Energy delivered to PG&E Energy
Trading was sold at negotiated market prices.
Deferred revenues of approximately $0.3 million are also included in
revenues from Niagara Mohawk during the year ended December 31, 1998. Deferred
revenues resulted from the consummation of the transactions pursuant to the MRA.
The $2.2 million payment made by the Partnership to Niagara Mohawk and the $10.3
million of payments received by the Partnership from Niagara Mohawk
(representing net receipts to the Partnership of approximately $8.1 million)
were a condition to the Amended and Restated Niagara Mohawk Power Purchase
Agreement and are being deferred to be amortized over the ten-year term of the
Amended and Restated Power Purchase Agreement. In addition, approximately $1.2
million in restructuring costs will also be amortized over the ten-year term of
the Amended and Restated Niagara Mohawk Power Purchase Agreement. Deferred
revenues of approximately $6.6 million were reported on the Partnership's
Consolidated Balance Sheet at December 31, 1998.
During the year ended December 31, 1997, with the exception of April,
May and September, Niagara Mohawk dispatched Unit 1 on-line. Energy delivered
during the months of June, July and August was sold at full contract rates.
Energy delivered during January, February, March and December was sold under
special dispatch arrangements which called for the pricing of delivered energy
at variable rates less than full contract rates. Revenues for energy pursuant to
special dispatch arrangements with Niagara Mohawk for the year ended December
31, 1998 were approximately $1.4 million as compared to approximately $6.2
million for the prior year.
Revenues from Unit 2 decreased approximately $1.4 million for the year
ended December 31, 1998 as compared to the prior year. During the year ended
December 31, 1998, revenues from Con Edison and PG&E Energy Trading were
approximately $122.8 million and $0.2 million as compared to approximately
$124.3 million and $0.1 million, respectively, for the prior year. The decrease
in revenues from Unit 2 for the year ended December 31, 1998 was primarily due
to the decrease in the Con Edison contract price for delivered energy resulting
from lower index fuel prices. The decrease in the price of energy was partially
offset by the increase in delivered energy as evidenced by the increase in
capacity factors from
25
81.18% to 87.89%. Revenues from PG&E Energy Trading resulted from sales of
generated capacity and energy in excess of contract amounts due under the Con
Edison Power Purchase Agreement.
Steam revenues for the year ended December 31, 1998 of approximately
$.05 million were reduced by a reserve of the same amount to reflect the annual
true-up so that General Electric would be charged a nominal amount which is the
annual equivalent of 160,000 lbs/hr. Steam revenues for the year ended December
31, 1997 of approximately $1.1 million were reduced by a reserve of
approximately $0.7 million to reflect the annual true-up. Delivered steam for
the year ended December 31, 1998 was approximately 1.4 billion pounds as
compared to approximately 1.5 billion pounds in the prior year.
Gas resale revenues for the year ended December 31, 1998 were
approximately $7.2 million on sales of approximately 3.2 million MMBtu's as
compared to approximately $13.6 million on sales of approximately 5.2 million
MMBtu's for the prior year. The $6.4 million decrease in gas resale revenues
during the year ended December 31, 1998 is primarily due to higher dispatch of
Units 1 and 2 and lower natural gas resale prices, which resulted in lower
volumes of natural gas becoming available for resale at lower prices. The
decrease in natural gas resale prices during the year ended December 31, 1998
generally resulted from more moderate temperatures in the Northeast region as
compared to colder temperatures, which resulted in higher demand for natural
gas, during the prior year. The Partnership entered into gas resales during
periods when Units 1 and 2 were not operating at full capacity.
Fuel costs for the year ended December 31, 1998 were approximately
$82.4 million on purchases of approximately 28.2 million MMBtu's as compared to
approximately $90.5 million on purchases of approximately 28.2 million MMBtu's
for the prior year. The $8.1 million decrease in the cost of fuel was primarily
due to lower contract firm fuel rates which resulted from lower index fuel
prices and lower transportation demand costs. During the years ended December
31, 1998 and 1997, fuel costs were reduced by approximately $0.9 million and
$1.8 million, respectively, as a result of the FERC approved settlement between
the Partnership and Tennessee. The Partnership has foreign currency swap
agreements to hedge against future exchange rate fluctuations under fuel
transportation agreements which are denominated in Canadian dollars. During the
years ended December 31, 1998 and 1997, fuel costs were increased by
approximately $2.5 million and $1.5 million, respectively, as a result of the
currency swap agreements.
Other operating and maintenance expenses for the year ended December
31, 1998 were approximately $17.6 million as compared to approximately $18.1
million for the prior year. The $0.5 million decrease in other operating and
maintenance expenses was primarily due to lower utility and depreciation
expenses.
Total other operating expenses, excluding amortization of deferred
financing charges, for the year ended December 31, 1998 were approximately $4.0
million as compared to approximately $5.4 million for the prior year. The $1.4
million decrease in other operating expenses, excluding amortization of deferred
financing charges, was due to lower affiliate
26
administrative services and lower external legal and consulting services. The
decrease in other operating expenses, excluding amortization of deferred
financing charges, was partially offset by a charge to write-off capitalized
start-up costs in accordance with Statement of Position 98-5. See Note 2 to the
Consolidated Financial Statements for a discussion of Statement of Position
98-5.
Amortization of deferred financing charges of approximately $1.2
million for the year ended December 31, 1998 was comparable to the prior year.
Deferred financing charges are amortized using the effective interest method.
Net interest expense for the year ended December 31, 1998 was
approximately $32.0 million as compared to approximately $32.2 million for the
prior year. The decrease in net interest expense is primarily due to lower bond
interest expense resulting from the lower principal balance outstanding.
Liquidity and Capital Resources
Net cash provided by operating activities for the year ended December
31, 1999 was approximately $33.3 million as compared to approximately $37.5
million for the prior year. Net cash provided by operating activities primarily
represents net income plus the net effect of recurring changes in cash receipts
and disbursements within the Partnership's operating assets and liability
accounts. Net cash provided by operating activities for the year ended December
31, 1998 also includes the net activity of approximately $6.9 million resulting
from the consummation of the transactions relating to the Amended and Restated
Niagara Mohawk Power Purchase Agreement pursuant to the MRA. See "Item 1.
Business, The Facility and Certain Project Contracts" for a detailed discussion
of the Amended and Restated Niagara Mohawk Power Purchase Agreement.
Net cash used in investing activities for the year ended December 31,
1999 was approximately $488,000 as compared to approximately $177,000 for the
prior year. Net cash flows used in investing activities primarily represent
additions to plant and equipment.
Net cash used in financing activities for the year ended December 31,
1999 was approximately $32.9 million as compared to approximately $36.8 million
for the prior year. The decrease in net cash used in financing activities for
the year ended December 31, 1999 is primarily due to a decrease in cash
deposited into the Debt Service Reserve Fund and a decrease in cash
distributions to the Partners. Pursuant to the Partnership's Depositary and
Disbursement Agreement, administered by Bankers Trust Company, as depositary
agent, the Partnership is required to maintain certain Restricted Funds. Net
cash flows used in financing activities for the years ended December 31, 1999
and 1998 primarily represent deposits of monies into the Debt Service Reserve
Fund, cash distributions to Partners and payments of principal on long-term
debt.
27
The debt service coverage ratio for 1999 calculated pursuant to the
Indenture was 1.75:1.
Credit Agreement
The Partnership has available for its use a $10.4 million Credit
Agreement ("Credit Agreement"), which is to be used by the Partnership for
required letters of credit related to various project contracts and for working
capital purposes. The maximum amount available under the Credit Agreement for
working capital purposes is $5.0 million. At December 31, 1999 and 1998, no
draws had been made against the outstanding letters of credit and no working
capital loans were outstanding under the Credit Agreement. The Credit Agreement
expires on August 1, 2001.
Funds
In connection with the sale of the Bonds, the Partnership entered into
the Deposit and Disbursement Agreement (the "D&D Agreement") which requires the
establishment and maintenance of certain segregated funds (the "Funds") and is
administered by Bankers Trust Company, as depositary agent. Pursuant to the D&D
Agreement, a number of Funds were established. Some of the Funds have been
terminated since the purposes of such Funds were achieved and are no longer
required, some Funds are currently active and some Funds activate at future
dates upon the occurrence of certain events. The significant Funds that are
currently active are the Project Revenue Fund, Major Maintenance Reserve Fund,
Interest Fund, Principal Fund, Debt Service Reserve Fund and two sub-funds of
the Partnership Distribution Fund.
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, 1999,
the balance in this Fund was approximately $7.5 million. During the year ending
December 31, 2000, no deposits are required to be made into the Fund.
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 as determined on the 20th
of the month. On December 26, 1999, the monies available in the Interest and
Principal Funds were used to make the semi-annual interest and principal
payments. Therefore, there were no balances remaining in the Interest and
Principal Funds at December 31, 1999 and 1998. The June 26, 2000 Interest and
28
Principal Fund Requirements will be approximately $16.9 million and
approximately $3.0 million, respectively.
The Fund Requirement for the Debt Service Reserve Fund is an amount
equal to the maximum amount of debt service due in respect of all the Bonds
outstanding for any six-month period during the succeeding three-year period. At
December 31, 1999, the balance in this Fund was approximately $22.7 million. The
June 26, 2000 Fund Requirement will remain at approximately $22.7 million.
The Partnership Distribution Fund has the lowest priority in 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.
Year Ending December 31, 2000
During 2000, the Partnership anticipates Con Edison to dispatch the
Unit 2 at levels consistent with the prior year. In order to achieve dispatch
levels similar to those of the prior year, or exceed them, the Partnership may
enter into special dispatch arrangements which will ultimately enhance the
operations, revenues and cash flows of the Partnership. Additionally, the
Amended and Restated Niagara Mohawk Power Purchase Agreement transfers dispatch
decision-making authority from Niagara Mohawk to the Partnership. In effect,
Unit 1 will operate on a "merchant-like" basis, whereby the Partnership will
have the ability and flexibility to dispatch Unit 1 based on then current market
conditions.
During the first quarter of 2000, natural gas resale prices and the
price of natural gas under the firm fuel contracts have been above prior year
prices and the Partnership anticipates, on the average, such prices to remain
above 1999 levels for the balance of 2000.
Future operating results and cash flows from operations are also
dependent on, among other things, the performance of equipment; levels of
dispatch; the receipt of certain capacity and other fixed payments; electricity
prices; natural gas resale prices; and fuel deliveries and prices. A significant
change in any of these factors could have a material adverse effect on the
results of operations for the Partnership.
The Partnership believes, based on current conditions and
circumstances, it will have sufficient cash flows from operations to fund
existing debt obligations and operating costs.
Year 2000
The Partnership successfully transitioned into the Year 2000 without
any Y2K-related service disruptions. There is, however, a risk that some
computer-related problems might not manifest themselves for a period of time and
that supplier or business partner Y2K problems may materialize and have an
adverse impact on the Partnership's operations.
29
As of December 31, 1999, expenditures to address potential Y2K problems
totaled $586,000. Such expenditures included systems replaced or enhanced for
general business purposes and for which implementation schedules were critical
to the Partnership's Y2K readiness.
Cautionary Statement Regarding Forward-Looking Statements
Certain statements included herein are forward-looking statements
concerning the Partnership's operations, economic performance and financial
condition. Such statements are subject to various risks and uncertainties.
Actual results could differ materially from those currently anticipated due to a
number of factors, including general business and economic conditions; the
performance of equipment; levels of dispatch; the receipt of certain capacity
and other fixed payments; electricity prices; natural gas resale prices; fuel
deliveries and prices; whether Con Edison were to prevail in its claim to Unit
2's excess natural gas volumes, and the related margins and issues related to
year 2000 compliance.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Partnership is exposed to market risk from changes in interest
rates and foreign currency exchange rates, which could affect its future results
of operations and financial condition. The Partnership manages its exposure to
these risks through its regular operating and financing activities.
Interest Rates
The Partnership's cash and restricted cash are sensitive to changes in
interest rates. Interest rate changes would result in a change in interest
income due to the difference between the current interest rates on cash and
restricted cash and the variable rate that these financial instruments may
adjust to in the future. A 10% decrease in year-end 1999 interest rates would
have resulted in a negative impact of approximately $0.2 million on the
Partnership's net income.
The Partnership's long-term bonds have fixed interest rates. Changes in
the current market rates for the bonds would not result in a change in interest
expense due to the fixed coupon rate of the bonds. See Notes 5 and 6 to the
Consolidated Financial Statements.
Foreign Currency Exchange Rates
The Partnership's currency swap agreements hedge against future
exchange rate fluctuations which could result in additional costs incurred under
fuel transportation agreements which are denominated in a foreign currency. In
the event a counterparty fails to
30
meet the terms of the agreements, the Partnership's exposure is limited to
the currency exchange rate differential. During the year ended December 31,
1999, the exchange rate differential would have a negative impact of
approximately $2.3 million on the Partnership's net income. See Notes 5 and 6 to
the Consolidated Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and supplementary data required by this item
are presented under Item 14 and are incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Information responding to Item 9 has been previously reported by the
Partnership in a current report on Form 8-K dated March 9, 1999.
31
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE FUNDING CORPORATION AND THE
MANAGING GENERAL PARTNER
The Managing General Partner is authorized to manage the day to day
business and affairs of the Partnership and to take actions which bind the
Partnership, subject to certain limitations set forth in the Partnership
Agreement. The Managing General Partner has a Board of Directors consisting of
two persons elected by its sole stockholder, JMC Selkirk Holdings, Inc.
("Holdings"), a direct subsidiary of Beale. Pursuant to a board representation
agreement with GPUI, Holdings may elect at least four members, and GPUI has the
right, at its option, to designate a fifth member of the Board of Directors of
the Managing General Partner.
The following tables set forth the names, ages and positions of the
directors and executive officers of the Funding Corporation and the Managing
General Partner and their positions with the Funding Corporation and the
Managing General Partner. Directors are elected annually and each elected
director holds office until a successor is elected. The executive officers of
each of the Funding Corporation and the Managing General Partner are chosen from
time to time by vote of its Board of Directors.
Selkirk Cogen Funding Corporation:
Name Age Position
---- --- --------
P. Chrisman Iribe............ 49 President and Director
Sanford L. Hartman........... 46 Director
John R. Cooper............... 52 Senior Vice President and
Chief Financial Officer
Gary F. Weidinger............ 51 Senior Vice President
David N. Bassett............. 53 Treasurer
Managing General Partner:
Name Age Position
---- --- --------
P. Chrisman Iribe............ 49 President and Director
Sanford L. Hartman........... 46 Director
John R. Cooper............... 52 Senior Vice President and
Chief Financial Officer
Gary F. Weidinger............ 51 Senior Vice President
David N. Bassett............. 53 Treasurer
P. Chrisman Iribe is President and Chief Operating Officer of PG&E
Generating Company ("PG&E Generating", formerly U.S. Generating Company), an
affiliate of the Partnership, and has been with PG&E Generating since it was
formed in 1989. Prior to
32
joining PG&E 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. Mr. Iribe has been a
Director of the Funding Corporation since 1996 and a Director of the Managing
General Partner since 1995.
Sanford L. Hartman is General Counsel of PG&E Generating, and has been
with PG&E Generating since 1990. Mr. Hartman assumed the role of General Counsel
in April 1999. Prior to joining PG&E Generating, Mr. Hartman was counsel to Long
Lake Energy Corporation, an independent power producer with headquarters in New
York City, and was an attorney with the Washington, D.C. law firm of Bishop,
Cook, Purcell & Reynolds.
John R. Cooper is Senior Vice President and Chief Operating Officer of
PG&E Generating, and has been with PG&E Generating, since it was formed in 1989.
Prior to joining PG&E Generating, he spent three years as Chief Financial
Officer with a European oil, shipping and banking group. Prior to 1986, Mr.
Cooper spent seven years with Bechtel Financing Services, Inc., where his last
position was Vice President and Manager.
Gary F. Weidinger is Senior Vice President Asset Management of PG&E
Generating, and has been with PG&E Generating since 1991. Mr. Weidinger was the
officer responsible for the Engineering Department prior to joining the
Operations Department in 1995. Mr. Weidinger has more than 25 years of
experience in the power generation business including management positions with
Bechtel Power, Puget Sound Power and Light and California Energy. He has also
managed a consulting firm providing services to power generation and industrial
customers.
David N. Bassett is Controller and Treasurer of PG&E Generating, and
has been with PG&E Generating since it was formed in 1989. Mr. Bassett oversees
all accounting and auditing activities, treasury functions and insurance for the
projects in which PG&E Generating or certain of its affiliates play a role.
Prior to joining PG&E 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.
33
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, 1999 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.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The Partnership is a limited partnership wholly owned by its Partners.
The following information is given with respect to the Partners of the
Partnership:
Nature
Name and Address of Beneficial Percentage
Title of Class of Beneficial Owner Ownership (1) Interest (2)
- -------------- ------------------- --------------- ------------
Partnership Interest JMC Selkirk, Inc. (3) Managing General (i) 2.0417%
One Bowdoin Square Partner and (ii) 22.4000%
Boston, Massachusetts 02114 Limited Partner (iii) 18.1440%
Partnership Interest PentaGen Investors, L.P.* (3)(4) Limited Partner (i) 5.2502%
One Bowdoin Square (ii) 57.6000%
Boston, Massachusetts 02114 (iii) 46.6560%
Partnership Interest RCM Selkirk GP, Inc.** General Partner (i) 1.0000%
711 Louisiana Street (iii) .2211%
Houston, Texas 77002 (5)
Partnership Interest RCM Selkirk LP, Inc.*** Limited Partner (i) 78.1557%
711 Louisiana Street (iii) 17.2789%
Houston, Texas 77002 (5)
Partnership interest EI Selkirk, Inc. (6) Limited Partner (i) 13.5523%
One Upper Pond Road (ii) 20.0000%
Parsippany, New Jersey 07054 (iii) 17.7000%
[FN]
* Formerly JMCS I Investors, L.P.
** Formerly Cogen Technologies GP, Inc.
*** Formerly Cogen Technologies LP, Inc.
(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.
34
(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) Beale (formerly J. Makowski Company) is the indirect
beneficial owner of JMC Selkirk and a 50% indirect beneficial
owner of Investors. The capital stock of Beale is held by PG&E
Generating Power Group, LLC (formerly USGenPower )(89.1%) and
Cogentrix (10.9%).
(4) 50% of the interests in Investors is beneficially owned by
Tomen Corporation, a Japanese trading company.
(5) RCM Selkirk GP is beneficially owned by Robert C. McNair
(88.3%) and members of his family (11.7%). As of February 4,
1999, RCM Selkirk LP is beneficially owned by 100% by Robert
C. McNair. Mr. McNair has voting control of each of RCM
Selkirk GP and RCM Selkirk LP.
(6) EI Selkirk is a wholly owned subsidiary of GPUI.
</FN>
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. RCM Selkirk GP and
RCM Selkirk LP are also affiliated.
All of the issued and outstanding capital stock of the Funding
Corporation is owned by the Partnership.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
JMCS I Management, an indirect, wholly-owned subsidiary of PG&E
Generating, provides management and administrative services for the Facility
under the Administrative Services Agreement. All of the directors and officers
of the Managing General Partner and the Funding Corporation listed in Item 10 of
this Report are also directors or officers, as the case may be, of JMCS I
Management. See Note 8 to the Consolidated Financial Statements for a discussion
of the Partnership's related party transactions.
35
PART IV
ITEM 14. FINANCIAL STATEMENTS, EXHIBITS AND REPORTS ON FORM 8-K
(a)1. Financial Statements
The following financial statements are filed as part of this Report:
Independent Auditors' Report for the year ended
December 31, 1999..................................... F-1
Report of Independent Public Accountants for the years ended
December 31, 1998 and 1997................................ F-2
Consolidated Balance Sheets as of December 31, 1999
and 1998.............................................. F-3
Consolidated Statements of Operations for the years ended
December 31, 1999, 1998 and 1997.......................... F-4
Consolidated Statements of Changes in Partners' Deficits
for the years ended December 31, 1999, 1998 and 1997.. F-5
Consolidated Statements of Cash Flows for the years ended
December 31, 1999, 1998 and 1997........................... F-6
Notes to Consolidated Financial Statements.................. F-7
2. 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.
36
INDEPENDENT AUDITORS' REPORT
To the Partners of
Selkirk Cogen Partners, L.P.:
We have audited the accompanying consolidated balance sheet of Selkirk Cogen
Partners, L.P. (a Delaware limited partnership) and its subsidiary
(collectively, the "Partnership") as of December 31, 1999, and the related
consolidated statements of operations, changes in partners' deficits, and cash
flows for the year then ended. These consolidated financial statements are the
responsibility of the Partnership's management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of the Partnership as
of December 31, 1999, and the results of its operations and its cash flows for
the year then ended, in conformity with generally accepted accounting
principles.
/s/ DELOITTE & TOUCHE LLP
- -------------------------
Boston, Massachusetts
January 14, 2000
F-1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners of Selkirk Cogen Partners, L.P.:
We have audited the accompanying consolidated balance sheets of Selkirk Cogen
Partners, L.P. (a Delaware limited partnership) and its subsidiary as of
December 31, 1998 and 1997, and the related consolidated statements of
operations, changes in partners' deficits and cash flows for the years then
ended. These consolidated financial statements are the responsibility of the
Partnership's management. Our responsibility is to express an opinion on these
consolidated 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 consolidated financial statements
referred to above present fairly, in all material respects, the financial
position of Selkirk Cogen Partners, L.P. and its subsidiary as of December 31,
1998 and 1997, and the results of their operations and their cash flows for the
years then ended, in conformity with generally accepted accounting principles.
/s/ ARTHUR ANDERSEN LLP
- -----------------------
Washington, D.C.
January 12, 1999
F-2
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(in thousands)
December 31, December 31,
1999 1998
----------- -----------
ASSETS
Current assets:
Cash and cash equivalents................................... $ 1,732 $ 1,839
Restricted funds............................................ 5,516 4,185
Accounts receivable......................................... 15,505 13,775
Due from affiliates......................................... 427 743
Fuel inventory and supplies................................. 6,831 5,033
Other current assets........................................ 195 333
---------- ----------
Total current assets................................... 30,206 25,908
Plant and equipment:
Plant and equipment, at cost................................ 371,690 371,202
Less: Accumulated depreciation............................. 74,656 62,203
---------- ----------
Plant and equipment, net................................. 297,034 308,999
Long-term restricted funds...................................... 30,217 28,188
Deferred financing charges, net of accumulated
amortization of $6,651 and $5,499 in
1999 and 1998, respectively................................ 9,630 10,782
---------- ----------
Total Assets $ 367,087 $ 373,877
========== ==========
LIABILITIES AND PARTNERS' DEFICITS
Current liabilities:
Accounts payable............................................ $ 2,126 $ 617
Accrued expenses............................................ 11,764 12,108
Due to affiliates........................................... 469 639
Current portion of long-term bonds.......................... 7,307 4,822
---------- ----------
Total current liabilities.............................. 21,666 18,186
Long-term liabilities:
Deferred revenue............................................ 5,981 6,565
Other long-term liabilities................................. 16,446 14,803
Long-term bonds, net of current portion..................... 373,826 381,133
---------- ----------
Total liabilities...................................... 417,919 420,687
Commitments and contingencies
Partners' Deficits:
General partners' deficits.................................. (497) (457)
Limited partners' deficits.................................. (50,335) (46,353)
---------- ----------
Total partners' deficits.................................. (50,832) (46,810)
---------- ----------
Total Liabilities and Partners' Deficits............... $ 367,087 $ 373,877
========== ==========
See notes to consolidated financial statements.
F-3
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
For the For the For the
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
1999 1998 1997
-------------------- -------------------- -------------------
Operating revenues:
Electric and steam..................................... $ 162,111 $ 158,805 $ 157,940
Gas resale............................................. 10,946 7,181 13,643
-------------------- -------------------- -------------------
Total operating revenues.......................... 173,057 165,986 171,583
Cost of revenues:
Fuel costs............................................. 82,815 82,392 90,526
Other operating and maintenance........................ 17,652 17,594 18,103
Depreciation........................................... 12,453 12,501 12,676
-------------------- -------------------- -------------------
Total cost of revenues............................ 112,920 112,487 121,305
-------------------- -------------------- -------------------
Gross profit.............................................. 60,137 53,499 50,278
Other operating expenses:
Administrative services, affiliates.................... 1,802 1,931 2,852
Other general and administrative....................... 1,599 2,036 2,562
Amortization of deferred financing charges............. 1,152 1,163 1,170
-------------------- -------------------- -------------------
Total other operating expenses.................... 4,553 5,130 6,584
-------------------- -------------------- -------------------
Operating income.......................................... 55,584 48,369 43,694
Interest (income) expense:
Interest income........................................ (2,355) (2,298) (2,325)
Interest expense....................................... 34,042 34,346 34,559
-------------------- -------------------- -------------------
Total interest expense, net....................... 31,687 32,048 32,234
-------------------- -------------------- -------------------
Net Income................................................ $ 23,897 $ 16,321 $ 11,460
==================== ==================== ===================
Net Income Allocation:
General partners....................................... $ 239 $ 163 $ 115
Limited partners....................................... 23,658 16,158 11,345
-------------------- -------------------- -------------------
Total............................................. $ 23,897 $ 16,321 $ 11,460
==================== ==================== ===================
See notes to consolidated financial statements.
F-4
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN PARTERNS' DEFICITS
For the years ended December 31, 1999, 1998 and 1997
(in thousands)
General Limited
Partners Partners Total
--------------------- ---------------------- ---------------------
Balance, January 1, 1997......................... $ (173) $ (18,637) $ (18,810)
Capital distributions....................... (253) (24,679) (24,932)
Net income.................................. 115 11,345 11,460
--------------------- ---------------------- ---------------------
Balance, December 31, 1997....................... (311) (31,971) (32,282)
--------------------- ---------------------- ---------------------
Capital distributions....................... (309) (30,540) (30,849)
Net income.................................. 163 16,158 16,321
--------------------- ---------------------- ---------------------
Balance, December 31, 1998....................... (457) (46,353) (46,810)
Capital distributions....................... (279) (27,640) (27,919)
Net income.................................. 239 23,658 23,897
--------------------- ---------------------- ---------------------
Balance, December 31, 1999....................... $ (497) $ (50,335) $ (50,832)
===================== ====================== =====================
See notes to consolidated financial statements.
F-5
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
For the For the For the
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
1999 1998 1997
---------------------- --------------------- --------------------
Cash flows from operating activities:
Net income $ 23,897 $ 16,321 $ 11,460
Adjustments to reconcile net income to net cash
provided by operating activities:
Start-up cost write-off....................... - 214 ---
Depreciation and amortization................. 13,605 13,664 13,846
Increase (decrease) in cash resulting from a
change in:
Restricted funds..................... (3,229) (1,696) (483)
Accounts receivable.................. (1,730) 3,321 2,628
Due from affiliates.................. 316 (729) 26
Fuel inventory and supplies.......... (1,798) (97) (535)
Other current assets................. 138 5 111
Accounts payable..................... 1,509 (1,046) 1,075
Accrued expenses..................... (344) (2,271) (2,070)
Due to affiliates.................... (170) 141 (439)
Deferred revenue..................... (584) 6,565 ---
Other long-term liabilities.......... 1,643 3,108 1,017
---------------------- --------------------- ---------------------
Net cash provided by
operating activities... 33,253 37,500 26,636
Cash flows from investing activities:
Plant and equipment additions........................ (488) (177) 16
---------------------- --------------------- ---------------------
Net cash (used in) provided by
investing activities... (488) (177) 16
Cash flows from financing activities:
Restricted funds..................................... (131) (2,674) (790)
Distributions to partners............................ (27,919) (30,849) (24,932)
Repayment of long-term debt.......................... (4,822) (3,298) (2,167)
Advances from customer............................... --- --- (17)
---------------------- --------------------- ---------------------
Net cash used in
financing activities...... (32,872) (36,821) (27,906)
Net (decrease) increase in cash and cash equivalents.... (107) 502 (1,254)
Cash and cash equivalents, beginning of year............ 1,839 1,337 2,591
---------------------- --------------------- ---------------------
Cash and cash equivalents, end of year.................. $ 1,732 $ 1,839 $ 1,337
====================== ===================== =====================
Supplemental cash flow information:
Cash paid for interest.............................. $ 34,047 $ 34,349 $ 34,561
====================== ===================== =====================
See notes to consolidated financial statements.
F-6
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
- --------------------------------------------------------------------------------
1. Organization and OPERATION
Selkirk Cogen Partners, L.P. was organized on December 15, 1989 as a
Delaware limited partnership. JMC Selkirk, Inc. is the managing general
partner. Selkirk Cogen Funding Corporation (the "Funding Corporation"), a
wholly-owned subsidiary of Selkirk Cogen Partners, L.P. (collectively, the
"Partnership"), was organized for the sole purpose of facilitating
financing activities of the Partnership and has no other operating
activities (Note 5). The obligations of the Funding Corporation with
respect to the bonds are unconditionally guaranteed by the Partnership.
The Partnership was formed for the purpose of constructing, owning and
operating a natural gas-fired combined-cycle cogeneration facility located
on General Electric Company's ("General Electric") property in Bethlehem,
New York (the "Facility"). The Facility consists of one unit ("Unit 1")
with an electric generating capacity of approximately 79.9 megawatts
("MW") and a second unit ("Unit 2") with an electric generating capacity
of approximately 265 MW. Unit 1 commenced commercial operations on April
17, 1992 and Unit 2 commenced commercial operations on September 1, 1994.
Both units are fueled by natural gas purchased from Canadian suppliers
(Note 7). Unit 1 and Unit 2 have been designed to operate independently
for electrical generation, while thermally integrated for steam
generation, thereby optimizing efficiencies in the combined performance of
the Facility.
The Facility is certified by the Federal Energy Regulatory Commission as a
qualifying facility ("Qualifying Facility") under the Public Utility
Regulatory Policy Act of 1978, as amended ("PURPA"). As a Qualifying
Facility, the prices charged for the sale of electricity and steam are not
regulated. Certain fuel supply and transportation agreements entered into
by the Partnership are also subject to regulation on the federal and
provincial levels in Canada. The Partnership has obtained all material
Canadian governmental permits and authorizations required for its
operation.
2. Summary of significant accounting policies
Basis of Presentation - The accompanying consolidated financial statements
include Selkirk Cogen Partners L.P. and the Funding Corporation. All
significant intercompany balances and transactions have been eliminated.
Use of Estimates - 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. Estimates also affect the reported
amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
Revenue Recognition - Revenues from the sale of electricity and steam are
recorded based on monthly output delivered as specified under contractual
terms. Revenues from the sale of excess gas are recorded in the month
sold.
F-7
2. Summary of significant accounting policies (CONTINUED)
Other Comprehensive Income - The Partnership had no elements of other
comprehensive income that are required to be reported or disclosed in
1999, 1998, or 1997.
Cash Equivalents - For the purposes of the accompanying consolidated
statements of cash flows, the Partnership considers all unrestricted,
highly liquid investments with original maturities of three months or less
to be cash equivalents.
Restricted Funds and Long-term Restricted Funds - Restricted funds and
long-term restricted funds include cash and cash equivalents whose use is
restricted under a deposit and disbursement agreement (the "D&D
Agreement," Note 5). Restricted funds associated with transactions or
events occurring beyond one year are classified as long-term. All other
restricted funds are classified as current assets.
Fuel Inventory and Supplies - Inventories are stated at the lower of cost
or market. Costs for materials, supplies and fuel oil inventories are
determined on an average cost method. As of December 31, 1999 and 1998,
fuel inventory and supplies consisted mainly of spare parts.
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:
Cognerating facility 30 Years
Computer systems 7
Office Equipment 5
A major overhaul reserve is recorded based upon the costs for periodic
overhauls of major systems within the Facility which are required on a
multiple-year cycle basis. Major overhaul reserve is included in other
long-term liabilities in the accompanying consolidated balance sheets and
had a carrying balance of approximately $7,866,000 and $6,543,000 at
December 31, 1999 and 1998, respectively. Provision for major overhaul
totaling $1,624,000, $1,814,000 and $1,801,000, for the years ended
December 31, 1999, 1998 and 1997, respectively, is included in other
operating and maintenance expenses in the accompanying consolidated
statements of operations. Other maintenance and repairs are charged to
expense as incurred.
Impairment of Long-Lived Assets - Long-lived assets to be held and used
are reviewed for impairment whenever circumstances indicate that the
carrying amount of an asset may not be recoverable. Long-lived assets to
be disposed of are reported at the lower of the carrying amount or fair
value, less cost of disposal.
Deferred Financing Charges - Deferred financing charges relate to costs
incurred for the issuance of long-term bonds and are amortized using the
effective interest method over the term of the related loans.
Real Estate Taxes - Real estate tax payments made under the Partnership's
payment in lieu of taxes ("PILOT") agreement (Note7) are recognized on a
straight-line basis over the term of the agreement.
F-8
2. Summary of significant accounting policies (CONTINUED)
Deferred Revenues - The net cash receipts and restructuring costs
resulting from the execution of the Amended and Restated Niagara Mohawk
Power Purchase Agreement are deferred and are amortized over the term of
the Amended and Restated Niagara Mohawk Power Purchase Agreement (Note 7).
Currency Swap Agreements - Gains and losses on currency exchange contracts
are deferred as hedges of firm commitments and are recognized in the
period when the hedged transactions are realized. In the event the
underlying transaction terminates, any unrecognized deferred gains and
losses on the related swap agreement will be recognized immediately (Note
5).
Income Taxes - The tax results of Partnership activities flow directly to
the partners; as such, the accompanying consolidated financial statements
do not reflect provisions for federal or state income taxes.
Fair Values of Financial Instruments - The estimated fair values of
financial instruments presented in Note 6 are based on pertinent
information available to management as of December 31, 1999 and 1998.
Although management is not aware of any factors that would significantly
affect the estimated fair values disclosure, such amounts have not been
comprehensively revalued for purposes of these financial statements since
that date, and accordingly, current estimates of fair value may differ
significantly from the amounts presented.
Change in Accounting Principle - In November 1998, the Partnership adopted
Statement of Position ("SOP") 98-5, "Reporting on the Costs of Start-Up
Activities," issued by the American Institute of Certified Public
Accountants. SOP 98-5 required start-up costs to be expensed as incurred
and start-up costs previously capitalized to be expensed as of the date of
adoption. As a result of adopting SOP 98-5, the Partnership wrote off
capitalized start-up costs of approximately $214,000 to other general and
administrative expenses in the accompanying 1998 consolidated statement of
operations.
New Accounting Pronouncements - In June 1998, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards
("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging
Activities," (as amended by SFAS No. 137). SFAS No. 133 establishes
accounting and reporting standards for derivative instruments, including
certain derivative instruments embedded in other contracts, and for
hedging activities. SFAS No. 133 is effective for the Partnership's fiscal
years beginning on January 1, 2001. Management has not completed an
evaluation of the impact on the Partnership's consolidated financial
statements of adopting this new standard.
Reclassifications - Certain reclassifications have been made in the 1998
and 1997 consolidated financial statements to conform to the current year
presentation.
F-9
3. Partners' capital
The general and limited partners and their respective equity interests are
as follows:
Interest
Partners Affiliated With Preferred Original
-------- --------------- --------- --------
General partners:
----------------
JMC Selkirk, Inc. Beale Generating Company 0.09% 1.00%
RCM Selkirk GP, Inc. RCM Holdings, Inc.*** 1.00 -
Limited partners:
----------------
JMC Selkirk, Inc. Beale Generating Company 1.95 21.40
PentaGen Investors, L.P. Beale Generating Company 5.25 57.60
El Selkirk, Inc. GPU International, Inc. 13.55 20.00
RCM Selkirk LP, Inc. RCM Holdings, Inc. 78.16 -
[FN]
*Formerly Cogen Technologies Selkirk, GP, Inc.
**Formerly Cogen Technologies Selkirk, LP, Inc.
***Formerly Cogen Technologies, Inc.
</FN>
Under the terms of the amended partnership agreement, 99% of cash
available for preferred distribution, as defined, is first allocated to
the partners in accordance with their respective preferred equity interest
and the remaining 1% is allocated based on the original ownership
structure between Beale Generating Company ("Beale") and GPU
International, Inc. ("GPUI"). Any remaining funds in excess of preferred
distribution are allocated 99% to the original equity holders and 1% to
the preferred equity holders. At the earlier of the eighteenth anniversary
of Unit 2's commercial operations (August, 2012) or the date on which all
the preferred partners achieve a specified return as defined in the
partnership agreement, distributions will be made in accordance with the
following residual interest: Beale at 64.8%, GPUI at 17.7%, and RCM
Holdings, Inc. at 17.5%.
4. Accrued Expenses
Accrued expenses consisted of the following at December 31 (in thousands):
1999 1998
Accrued fuel costs $ 6,836 $ 7,652
Accrued PILOT 1,350 1,250
Accrued utilities 899 852
Accured operation and maintenance
expenses 525 408
Accrued bond interest 375 379
Other accrued expenses 1,779 1,567
------- --------
Total $11,764 $ 12,108
======= ========
F-10
5. Debt financing
Long-Term Bonds - On May 9, 1994, the Funding Corporation issued an
aggregate of $392,000,000 in bonds. The bonds consist of a $165,000,000
bond bearing interest at 8.65% per annum through December 26, 2007.
Principal and interest are payable semi-annually on June 26 and December
26. Principal payments commenced on June 26, 1996. The bonds also include
a $227,000,000 bond bearing interest at 8.98% per annum through June 26,
2012. Interest is payable semi-annually on June 26 and December 26 and
principal payments commence on December 26, 2007 and are payable
semi-annually thereafter.
The scheduled principal payments on the bonds are as follows:
(In thousands)
2000 $ 7,307
2001 11,062
2002 13,529
2003 17,365
2004 19,587
2005 and thereafter 312,283
-----------
$ 381,133
===========
The bonds are secured by substantially all of the assets of the
Partnership and are non-recourse to the individual partners. The trust
indenture restricts the ability of the Partnership to make distributions
to the partners under certain circumstances.
In connection with the sale of the bonds, the Partnership entered into the
D&D Agreement which requires the establishment and maintenance of certain
segregated funds (the "Funds") and is administered by Bankers Trust
Company as trustee (the "Trustee"). The Funds that are active and included
in current restricted funds in the accompanying consolidated balance
sheets include the Project Revenue Fund, Principal Fund, Interest Fund,
and two sub-funds of the Partnership Distribution Fund. The Funds that are
active and included in long-term restricted funds in the accompanying
consolidated balance sheets are the Major Maintenance Reserve Fund and
Debt Service Reserve Fund.
All Partnership cash receipts and operating cost disbursements flow
through the Project Revenue Fund. As determined on the 20th of each month,
any monies remaining in the Project Revenue Fund after the payment of
operating costs are used to fund the above named Funds based upon the fund
hierarchy and in amounts 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. Fund requirement for
the Major Maintenance Reserve Fund 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, 1999, the balance in the Major
Maintenance Reserve Fund was approximately $7,531,000.
The Interest and Principal Funds relate primarily to the current debt
service on the outstanding Bonds. The applicable fund requirement for the
Interest and Principal Funds are the amounts due and payable on the next
semi-annual payment date.
F-11
5. Debt financing (CONTINUED)
Long-Term Bonds (Continued) - The fund requirement for the Debt Service
Reserve Fund is an amount equal to the maximum debt service for any
six-month period during the succeeding three-year period. At December 31,
1999, the balance in the Debt Service Reserve Fund was approximately
$22,685,000.
The Partnership Distribution Fund has the lowest priority in the fund
hierarchy. 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. The
Partnership Distribution Fund does not have a fund requirement.
Credit Agreement - The Partnership has a combined working capital and bank
reimbursement agreement, as amended ("Credit Agreement"), with a combined
maximum available credit of $10,389,528 through August 1, 2001.
Outstanding balances bear interest at prime rate plus .375 % per annum
with principal and interest payable monthly in arrears. The Credit
Agreement is available to the Partnership for the purpose of meeting
letters of credit requirements under various project contracts. The Credit
Agreement is also available to the Partnership for the purpose of meeting
working capital requirements. The maximum amount available under the
working capital arrangement is $5,000,000. As of December 31, 1999 and
1998, there were no amounts drawn or balances outstanding under either the
letters of credit or the working capital arrangement.
Currency Swap Agreements - The Partnership has two foreign currency
exchange agreements to hedge against fluctuations in fuel transportation
costs which are denominated in Canadian dollars. Under the Unit 1 currency
exchange agreement, the Partnership exchanges approximately $368,000 U.S.
dollars for $458,000 Canadian dollars on a monthly basis. The agreement
has a term of ten years and expires on December 25, 2002. Under the Unit 2
currency exchange agreement, which commenced on May 25, 1995 and
terminates on December 25, 2004, the Partnership exchanges approximately
$1,044,000 U.S. dollars for $1,300,000 Canadian dollars on a monthly
basis. For the years ended December 31, 1999, 1998 and 1997, amounts
charged to fuel costs as a result of losses realized from these agreements
totaled approximately $2,342,000, $2,480,000 and $1,514,000, respectively
(Note 2).
In addition, the Partnership is exposed to credit loss under the currency
agreements. In the event that a counterparty fails to meet the terms of
the agreements, the Partnership's exposure is limited to the currency
exchange rate differential. The Partnership does not anticipate
nonperformance by the counterparties.
6. FAIR VALUES OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used by the Partnership in
estimating the fair value of its financial instruments:
Cash and Cash Equivalents, Restricted Funds, Due from Affiliates, Due to
Affiliates, Accounts Receivable, Accounts Payable, and Accrued Expenses -
The carrying amounts reported in the accompanying consolidated balance
sheets of these accounts approximate their fair values due primarily to
the short-term maturities of these accounts.
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, 1999 and 1998 was
approximately $383,915,000 and $420,252,000, respectively.
F-12
6. FAIR VALUES OF FINANCIAL INSTRUMENTS (CONTINUED)
Currency Swap Agreements - The currency exchange agreements do not have
stated values at December 31, 1999 and 1998. The fair value of the
currency exchange arrangements represents the termination liability of
approximately $6,777,000 and $11,911,000 at December 31, 1999 and 1998,
respectively, and is estimated based on current exchange rates.
7. COMMITMENTS AND CONTINGENCIES
Power Purchase Agreements, Electricity - Prior to July 1, 1998, the
Partnership had a power purchase agreement, as amended, with Niagara
Mohawk Power Corporation ("Niagara Mohawk") for the sale of electricity.
The agreement was for a twenty year period terminating in April 2012. As a
result of Niagara Mohawk's restructuring of its power purchase agreements,
on August 31, 1998, the Partnership and Niagara Mohawk signed an Amended
and Restated Niagara Mohawk Power Purchase Agreement, effective July 1,
1998, for a term of ten years. The Amended and Restated Niagara Mohawk
Power Purchase Agreement transfers dispatch decision-making authority from
Niagara Mohawk to the Partnership. In effect, Unit 1 will operate on a
"merchant-like" basis, whereby the Partnership will have the ability and
flexibility to dispatch Unit 1 based on current market conditions.
As part of the restructuring of Niagara Mohawk's business including the
Amended and Restated Niagara Mohawk Power Purchase Agreement, Niagara
Mohawk paid the Partnership a net amount of approximately $8,143,000 which
was recorded by the Partnership as deferred revenue. Both the deferred
revenue and certain restructuring costs totaling approximately $1,233,000,
are amortized over the term of the Amended and Restated Niagara Mohawk
Power Purchase Agreement. The balance of the unamortized deferred revenues
was approximately $5,981,000 and $6,565,000 in the accompanying
consolidated balance sheets at December 31, 1999 and 1998, respectively.
The Partnership also has a power purchase agreement with Consolidated
Edison Company of New York ("Con Edison") for an initial term of 20 years
which began on September 1, 1994, the date Unit 2's commercial operations
commenced. The contract may be extended under certain circumstances.
The Con Edison power purchase agreement provides Con Edison the rights to
schedule Unit 2 for dispatch on a daily basis at full capability, partial
capability or off-line. Con Edison's scheduling decisions are required to
be based in part on economic criteria which, pursuant to the governing
rules of the New York Power Pool, take into account the variable cost of
the electricity to be delivered. Certain payments under these agreements
are unaffected by levels of dispatch. However, certain payments may be
rebated or reduced to Con Edison if the Partnership does not maintain a
minimum availability level.
On July 21, 1998, the NYPSC approved a plan submitted by Con Edison for
the divestiture of certain of its generating assets (the "Con Edison
Divestiture Plan"). As of December 31, 1999, the Partnership is not able
to determine whether the Con Edison Divestiture Plan will have an effect
on the Con Edison power purchase agreement or on the Partnership's future
operations.
F-13
7. COMMITMENTS AND CONTINGENCIES (CONTINUED)
Steam Sales Agreements -The Partnership has a steam sales agreement, as
amended, with General Electric that has a term of 20 years from the
commercial operations date of Unit 2 and may be extended under certain
circumstances. Under the steam sales agreement, General Electric is
obligated to purchase the minimum quantities of steam necessary for the
Facility to maintain its Qualifying Facility status (Note 1). In the event
General Electric fails to meet minimum purchase quantity, the Partnership
may acquire title to the Facility site and terminate the Lease Agreement
at no cost to the Partnership.
The agreement provides General Electric the right of first refusal to
purchase the Facility, subject to certain pricing considerations.
Additionally, General Electric has the right to purchase the boiler
facility that produces steam at a mutually agreed upon price upon
termination of the steam sale agreement. The steam sales agreement may be
terminated by the Partnership with a one-year advanced written notice upon
the termination of either Niagara Mohawk or Con Edison power purchase
agreement, whichever is earlier. The steam sales agreement may also be
terminated by General Electric with a two-year advanced written notice if
General Electric's plant no longer has a requirement for steam.
Fuel Supply and Transportation Agreements - The Partnership has entered
into a firm natural gas supply agreement, as amended, with Paramount
Resources Ltd., a Canadian corporation, for Unit 1. The agreement has an
initial term of 15 years which began in November 1992, with an option to
extend for an additional four years upon satisfaction of certain
conditions.
The Partnership has firm natural gas supply agreements with various
suppliers for Unit 2. The agreements have an initial term of 15 years
beginning on November 1, 1994, and an option to extend for an additional
five-year term upon satisfaction of certain conditions.
Each Unit 2 natural gas supply contract requires the Partnership to
purchase a minimum of 75% of the maximum annual contract volume every
year. If the Partnership fails to meet this minimum quantity, the
shortfall (the difference between the minimum required volume and the
actual nomination) must be made up within the next two years. If the
Partnership is not able to make up the shortfall within the next two
years, the suppliers have the right to reduce the maximum daily contract
quantity by the shortfall. For the years ended December 31, 1999, 1998 and
1997, the Partnership purchased gas totaling approximately $34,209,000,
$32,048,000 and $38,279,000 respectively, under these agreements.
The Partnership has three 20-year firm fuel transportation service
agreements for Unit 1 commencing November 1, 1992. In accordance with one
of these agreements, the Partnership posted a letter of credit of
approximately $586,000 in October 1992.
The Partnership has three firm fuel transportation service agreements for
Unit 2. The agreements commenced in November 1994 and have terms of 20
years. The Partnership and two fuel suppliers, on behalf of the
Partnership, have posted letters of credit totaling approximately
$10,507,000 Canadian dollars under one of the three agreements. The
Partnership will reimburse to the fuel suppliers all costs related to
obtaining and maintaining the letters of credit. The Partnership also
posted two letters of credit related to the remaining two firm fuel
transportation agreements for approximately $796,000 and $2,090,000,
respectively.
F-14
7. COMMITMENTS AND CONTINGENCIES (CONTINUED)
Electric Interconnection and Transmission Agreements - The Partnership
constructed an interconnection facility to transfer power from Unit 1 to
Niagara Mohawk and has transferred the title of the facility to Niagara
Mohawk. The Partnership has agreed to reimburse Niagara Mohawk $150,000
annually for the operation and maintenance of the facility. The term of
the agreement is 20 years from the commercial operations date of Unit 1
through April 16, 2012 and may be extended if the power purchase agreement
with Niagara Mohawk is extended.
The Partnership has a 20-year firm transmission agreement with Niagara
Mohawk, as amended, to transmit power from Unit 2 to Con Edison through
August 31, 2014. In connection with this agreement, the Partnership
constructed an interconnection facility and in 1995 transferred the title
of the facility to Niagara Mohawk . Under the terms of this agreement, the
Partnership will reimburse Niagara Mohawk $450,000 annually for the
maintenance of the facility.
Site Lease -The Partnership has an operating lease agreement with General
Electric. The amended lease term expires on August 31, 2014 and is
renewable for the greater of five years or until termination of any power
sales contract, up to a maximum of 20 years. The lease may be terminated
by the Partnership under certain circumstances with the appropriate
written notice during the initial term. Annual fixed rent expense was
approximately $1,000,000.
Payment in Lieu of Taxes Agreement - In October 1992, the Partnership
entered into a PILOT agreement with the Town of Bethlehem Industrial
Development Agency ("IDA"), a corporate governmental agency, which exempts
the Partnership from all property taxes, except for special assessments.
The agreement commenced on January 1, 1993, and will terminate on December
31, 2012. PILOT payments are due semi-annually in equal installments and
are payable in future years as follows:
(In thousands)
2000 $ 2,700
2001 2,900
2002 3,100
2003 3,300
2004 3,500
2005 and thereafter 32,400
-----------
$ 47,900
===========
Other Agreements - The Partnership has an operations and maintenance
services agreement with General Electric whereby General Electric provides
certain operation and maintenance services to both Unit 1 and Unit 2 on a
cost-plus-fixed-fee basis through August 2001. In addition, the
Partnership has a 20-year take-or-pay water supply agreement with the Town
of Bethlehem under which the Partnership is committed to purchase a
minimum of $1,000,000 of water supply annually. The agreement is subject
to adjustment for changes in market rates beginning in October 2002.
Other Contingencies - The Partnership is a party in various legal
proceedings and potential claims arising in the ordinary course of its
business. Management does not believe that the resolution of these matters
will have a material adverse effect on the Partnership's consolidated
financial position or results of operations.
F-15
8. Related parties
JMCS I Management manages the day-to-day operation of the Partnership and
is compensated at agreed-upon billing rates which are adjusted
quadrennially in accordance with an administrative services agreement. All
officers and directors of JMC Selkirk, Inc. are also officers and
directors of JMCS I Management. For the years ended December 31, 1999,
1998 and 1997, expenses incurred for services provided by JMCS I
Management totaled approximately $2,027,000, $2,651,000 and $2,852,000,
respectively. In addition, during the year ended December 31, 1998,
approximately $720,000 of legal and financial consulting services payable
to JMCS I Management was capitalized in connection with the execution of
the Niagara Mohawk Power Purchase Agreement (Note 7). The cost of services
provided by JMCS I Management, net of capitalized costs are included in
administrative services - affiliates in the accompanying consolidated
statements of operations.
The Partnership purchases and sells gas to affiliates of JMC Selkirk, Inc.
at fair value. Gas purchased from affiliates of JMC Selkirk, Inc. totaled
approximately $140,000, $1,649,000, and $346,000, respectively, in 1999,
1998, and 1997, and gas sold to affiliates of JMC Selkirk, Inc. totaled
approximately $453,000, $1,476,000, and $26,000, respectively. Spot gas
purchases and the net effect of purchases and sales of gas along the
pipelines are recorded as fuel costs and sales of excess natural gas
supplies are recorded as gas resales in the accompanying consolidated
statements of operations.
In May 1996, the Partnership entered into an enabling agreement with PG&E
Energy Trading - Power, L.P. (formerly US Gen Power Services, L.P.), an
affiliate of JMC Selkirk, Inc., to purchase and sell electric capacity,
electric energy, and other services. For the years ended December 31,
1999, 1998 and 1997, sales of energy , capacity and other services totaled
approximately $5,515,000, $2,009,000 and $100,000, respectively.
The Partnership has two agreements with Iroquois Gas Transmission System
("IGTS"), an indirect affiliate of JMC Selkirk, Inc., to provide firm
transportation of natural gas from Canada.
* * * * * *
F-16
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
37
10.1.1(1) Credit Bank Working Capital and Reimbursement Agreement, dated
as of May 1, 1994, among the Partnership, The Chase Manhattan
Bank, N.A. ("Chase"), as Agent, and the other Credit Banks
identified therein
10.1.2(1) Amendment No. 1 to Credit Agreement, dated August 11, 1994,
among the Partnership, Dresdner Bank AG, New York Branch, and
Chase
10.1.3(6) Amendment No. 2 to Credit Agreement, dated April 7, 1995,
between the Partnership and Dresdner Bank AG, New York Branch
10.1.4(6) Amendment No. 3 to Credit Agreement, dated July 1, 1997,
between the Partnership and Dresdner Bank AG, New York Branch
10.1.5(17) Amendment No. 4 to Credit Agreement, dated November 16, 1998,
between the Partnership and Dresdner Bank AG, New York Branch
10.1.6(1) Loan Agreement, dated as of May 1, 1994, between the
Partnership, Chase, as Agent, and other Bridge Banks identified
therein
10.1.7(1) Amended and Restated Loan Agreement, dated as of May 1, 1994,
between the Funding Corporation and the Partnership
10.1.8(1) Agreement of Consolidation, Modification and Restatement of
Notes ($227,000,000), dated as of May 1, 1994, between the
Partnership and the Funding Corporation, together with
Endorsement from the Funding Corporation dated May 9, 1994
10.1.9(1) Agreement of Consolidation, Modification and Restatement of
Notes ($165,000,000), dated as of May 1, 1994, between the
Partnership and the Funding Corporation, together with
Endorsement from the Funding Corporation dated May 9, 1994
10.2 Power Purchase Agreements
10.2.1(1) Power Purchase Agreement, dated as of December 7, 1987, between
JMC Selkirk and Niagara Mohawk Power Corporation ("Niagara
Mohawk")
10.2.2(1) Amendment to Power Purchase Agreement, dated as of December 14,
1989, between JMC Selkirk and Niagara Mohawk
10.2.3(1) Second Amendment to Power Purchase Agreement, dated as of
January, 25, 1990, between JMC Selkirk and Niagara Mohawk
38
10.2.4(1) Third Amendment to Power Purchase Agreement, dated as of
October 23, 1992 between JMC Selkirk and Niagara Mohawk
10.2.5(3) Fourth Amendment to Power Purchase Agreement, dated as of June
26, 1996 between the Partnership and Niagara Mohawk
10.2.6(8) Amended and Restated Power Purchase Agreement dated as of July
1, 1998 between the Partnership and Niagara Mohawk
10.2.7(9) Mutual General Release and Agreement dated as of July 1, 1998
between the Partnership and Niagara Mohawk
10.2.8(1) Agreement dated as of March 31, 1994, between the Partnership
and Niagara Mohawk
10.2.9(5) Letter Agreement dated as of April 18, 1997, between the
Partnership and Niagara Mohawk
10.2.10(1) Termination of the Subordination Agreement and the Assignment
of Contracts and Security Agreement, as amended, dated May 9,
1994, among Niagara Mohawk, Chase, as Agent, and the
Partnership
10.2.11(1) License Agreement between the Partnership and Niagara Mohawk,
dated as of October 23, 1992
10.2.12(1) Power Purchase Agreement, dated as of April 14, 1989, between
Con Edison Company of New York, Inc. ("Con Edison") and JMC
Selkirk
10.2.13(1) Rider to Power Purchase Agreement, dated as of September 13,
1989, between Con Edison and JMC Selkirk
10.2.14(1) First Amendment to Power Purchase Agreement, dated as of
September 13, 1991, between Con Edison and JMC Selkirk
10.2.15(1) Letter Agreement Regarding Extending the Term of the Power
Purchase Agreement, dated as of May 28, 1992, between Con
Edison and JMC Selkirk
10.2.16(1) Second Amendment to Power Purchase Agreement, dated as of
October 22, 1992, between Con Edison and JMC Selkirk
10.2.17(4) Third Amendment to Power Purchase Agreement, dated as of
September 13, 1996, between Con Edison and the Partnership
39
10.2.18(1) Letter Agreement Regarding Arbitration, dated October 22, 1992,
between Con Edison and JMC Selkirk
10.2.19(1) Letter Agreement Regarding Sale of Capacity above 265 MW, dated
as of October 22, 1992, between Con Edison and JMC Selkirk
10.2.20(1) Notice, Certificate and Waiver of Con Edison for assignment by
Selkirk Cogen Partners, L.P. ("SCP II") to the Partnership
pursuant to the merger, dated October 19, 1992
10.2.21(1) Letter Agreement regarding Alternative Fuel Supply, dated as of
July 29, 1994, between Con Edison and the Partnership
10.3 Construction Agreements
10.3.1(1) Engineering, Procurement and Construction Services Agreement,
dated as of October 21, 1992, between the Partnership and
Bechtel Construction of Nevada and Bechtel Associates
Professional Corporation (the "Contractor")
10.4 Steam Agreements
10.4.1(1) Agreement for the Sale of Steam, dated as of October 21, 1992,
between the Partnership and General Electric Company ("General
Electric")
10.4.2(1) Amendment to Steam Sales Agreement, dated as of August 12,
1993, between the Partnership and General Electric
10.4.3(1) Amended and Restated Operation and Maintenance Agreement, dated
as of October 22, 1992, between the Partnership and General
Electric
10.4.4(1) Second Amendment to Steam Sales Agreement, dated December 7,
1994, between the Partnership and General Electric
10.4.5(2) Third Amendment to Steam Sales Agreement, dated May 31, 1995,
between the Partnership and General Electric
10.5 Fuel Supply Contracts
10.5.1(1) Amended and Restated Gas Purchase Contract, dated as of
September 26, 1992, between Paramount Resources Ltd.
("Paramount") and the Partnership
40
10.5.2(1) First Amendment to the Amended and Restated Gas Purchase
Contract, dated as of October 5, 1992, between Paramount and
the Partnership
10.5.3(1) Second Amendment to the Amended and Restated Gas Purchase
Contract, dated as of December 1, 1993, between Paramount and
the Partnership
10.5.4(10) Second Amended and Restated Gas Purchase Contract, dated as of
May 6, 1998, between the Partnership and Paramount
10.5.5(1) Letter Agreement, dated as of October 25, 1993, between the
Partnership and Paramount
10.5.6(1) Indemnity Agreement, dated as of February 20, 1989, by the
Partnership in favor of Paramount
10.5.7(1) Letter Agreement, dated as of June 11, 1990, between the
Partnership and Paramount
10.5.8(1) Indemnity Amending and Supplemental Agreement, dated as of June
19, 1990, between the Partnership and Paramount
10.5.9(1) Intercreditor Agreement, dated as of October 21, 1992, between
Paramount, the Partnership and Chase, as Agent
10.5.10(1) Specific Assignment of Unit 1 TransCanada Transportation
Contract, dated as of December 20, 1991, by the Partnership to
Paramount
10.5.11(1) Amendment No. 1 to Specific Assignment, dated as of October 21,
1992, between the Partnership and Paramount
10.5.12(1) Amended and Restated Gas Purchase Agreement, dated as of
January 21, 1993, between the Partnership and Atcor Ltd.
("Atcor")
10.5.13(1) Amended and Restated Gas Purchase Agreement, dated as of
October 22, 1992, between the Partnership, as assignee, and
Imperial Oil Resources ("Imperial")
10.5.14(1) Amended and Restated Gas Purchase Agreement, dated as of
October 22, 1992, between the Partnership, as assignee, and
PanCanadian Pertroleum Limited ("PanCanadian")
10.5.15(1) Back-up Fuel Supply Agreement, dated as of June 18, 1992,
between Phibro Energy USA, Inc. ("Phibro") and SCP II
41
10.6 Fuel Transportation Agreements
10.6.1(1) Gas Transportation Contract for Firm Reserved Service, dated as
of February 7, 1991, between Iroquois Gas Transmission System,
L.P. ("Iroquois") and the Partnership
10.6.2(1) Letter Agreement, dated June 30, 1993, from Iroquois and
acknowledged and accepted for the Partnership by JMC Selkirk
10.6.3(1) Firm Service Contract for Firm Transportation Service, dated as
of September 6, 1991, between TransCanada PipeLines Limited
("TransCanada") and the Partnership
10.6.4(1) Amending Agreement, dated as of May 28, 1993, between the
Partnership and TransCanada
10.6.5(11) Amending Agreement, dated as of July 20, 1998, between the
Partnership and TransCanada
10.6.6(1) Firm Natural Gas Transportation Agreement, dated as of April
18, 1991, between Tennessee Gas Pipeline and the Partnership
10.6.7(1) Clarification Letter from Tennessee, dated April 18, 1991,
between the Partnership and Tennessee
10.6.8(1) Supplemental Agreement (Unit 1), dated April 18, 1991, between
the Partnership and Tennessee
10.6.9(1) Operational Balancing Agreement, dated as of September 1, 1993,
between the Partnership and Tennessee
10.6.10(1) Interruptible Transportation Agreement, dated as of September
1, 1993, between the Partnership and Tennessee
10.6.11(1) License Agreement for the Ten-Speed 2 System, dated as of July
21, 1993, between the Partnership, Tennessee, Midwestern Gas
Transmission Company and East Tennessee Natural Gas Company
10.6.12(1) Firm Service Contract for Firm Transportation Service, dated as
of March 16, 1994, between the Partnership and TransCanada
10.6.13(1) Letter Agreement, dated as of March 24, 1994, between the
Partnership and TransCanada
42
10.6.14(1) Gas Transportation Contract for Firm Reserved Service, dated as
of April 5, 1994, between the Partnership and Iroquois
10.6.15(1) Letter Agreement, dated as of March 31, 1994, between the
Partnership and Iroquois
10.6.16(1) Firm Natural Gas Transportation Agreement, dated as of April
11, 1994, between the Partnership and Tennessee
10.6.17(1) Tennessee Supplemental Agreement (Unit 2), dated as of October
21, 1992, between Tennessee and the Partnership
10.6.18(1) Letter Agreement, dated September 22, 1993, between the
Partnership and Tennessee
10.6.19(2) Consent and Agreement, dated May 15, 1995, between the
Partnership, Iroquois and the Trustee
10.7 Transmission and Interconnection Agreements
10.7.1(1) Transmission Services Agreement, dated as of December 13, 1990,
between Niagara Mohawk and SCP II
10.7.2(1) Notice, Certificate, Agreement, Waiver and Acknowledgment to
Niagara Mohawk of Assignment of Transmission Agreement to the
Partnership, dated as of October 23, 1992
10.7.3(1) Interconnection Agreement (Unit 1), dated as of October 20,
1992, between Niagara Mohawk and SCP II
10.7.4(1) Interconnection Agreement (Unit 2), dated as of October 20,
1992, between Niagara Mohawk and SCP II
10.8 Administrative Services Agreements and Water Supply Agreement
10.8.1(1) Project Administrative Services Agreement, dated as of June 15,
1992, between JMCS I Management, Inc. ("JMCS I Management") and
the Partnership
10.8.2(1) First Amendment to Project Administrative Services Agreement,
dated as of October 23, 1992, between JMCS I Management and the
Partnership
43
10.8.3(1) Second Amendment to Project Administrative Services Agreement,
dated as of May 1, 1994, between JMCS I Management and the
Partnership
10.8.4(1) Water Supply Agreement, dated as of May 6, 1992, between the
Town of Bethlehem, New York and the Partnership
10.9 Real Estate Documents
10.9.1(1) Second Amended and Restated Lease Agreement, dated as of
October 21, 1992, between the Partnership and General Electric
10.9.2(1) Amended and Restated First Amendment to Second Amended and
Restated Lease Agreement, dated as of April 30, 1994, between
the Partnership and General Electric
10.9.3(1) Unit 2 Grant of Easement, dated as of October 21, 1992, made by
General Electric in favor of the Partnership (regarding Unit 2
Substation and Transmission Line)
10.9.4(1) Declaration of Restrictive Covenants by General Electric, dated
as of October 21, 1992 (regarding Wetlands Remediation Areas)
10.9.5(1) Utilities Building Lease Agreement, dated as of October 21,
1992, between General Electric, as Landlord, and the
Partnership, as Tenant
10.9.6(1) Easement Agreement, dated as of May 27, 1992, between Charles
Waldenmaier and the Partnership, as assignee
10.9.7(1) Facility Lease Agreement, dated as of October 21, 1992, between
the Partnership, as Landlord, and the Town of Bethlehem, New
York Industrial Development Agency ("IDA"), as Tenant
10.9.8(1) Amended and Restated First Amendment to Facility Lease
Agreement, dated as of April 30, 1994, between the Partnership
and the IDA
10.9.9(1) Sublease Agreement, dated as of October 21, 1992, between the
Partnership, as Subtenant, and the IDA, as Sublandlord
10.9.10(1) Amended and Restated First Amendment to Sublease Agreement,
dated as of April 30, 1994, between the Partnership and the IDA
10.9.11(1) Payment in Lieu of Taxes Agreement, dated as of October 21,
1992, between the Partnership and the IDA
44
10.10 Security Documents
10.10.1(1) Assignment of Agreements, dated as of May 1, 1994, among Yasuda
Bank and Trust Company (U.S.A.) ("Yasuda"), Dresdner Bank AG,
New York and Grand Cayman Branches ("Dresdner"), the Depositary
Agent, the Collateral Agent, the Partnership and the Funding
Corporation
10.10.2(1) Depositary Agreement, dated as of May 1, 1994, among the
Funding Corporation, the Partnership, Bankers Trust Company as
collateral agent ("Collateral Agent") and Bankers Trust
Company, as depositary agent (the "Depositary Agent")
10.10.3(1) Equity Contribution Agreement, dated as of May 1, 1994, among
the Partnership, Cogen LP, Cogen GP, Makowski Selkirk and Chase
10.10.4(1) Cash Collateral Agreement, dated as of May 1, 1994, among
Makowski Selkirk, the Partnership and Chase, as Agent
10.10.5(1) Cash Collateral Agreement, dated as of May 1, 1994, among Cogen
LP, the Partnership and Chase, as Agent
10.10.6(1) Cash Collateral Agreement, dated as of May 1, 1994, among Cogen
GP, the Partnership and Chase, as Agent
10.10.7(1) Agreement of Spreader, Consolidation and Modification of
Leasehold Mortgages, Security Agreements and Fixture Financing
Statements, (the "First Consolidated Mortgage"), dated as of
May 1, 1994, in the principal amount of $227,000,000 among the
Partnership, the IDA and the Collateral Agent
10.10.8(1) Agreement of Spreader, Consolidation and Modification of
Leasehold Mortgages, Security Agreements and Fixture Financing
Statements, dated as of May 1, 1994, in the principal amount of
$122,000,000 among the Partnership, the IDA and the Collateral
Agent
10.10.9(1) Agreement of Spreader and Modification of Leasehold Mortgage
(the "Restated Mortgage"), dated as of May 1, 1994, in the
principal amount of $43,000,000 among the Partnership, the IDA
and the Collateral Agent
10.10.10(1) Agreement of Modification and Severance of Mortgage (the
"Mortgage Splitter Agreement"), dated as of May 1, 1994, among
the Partnership, the IDA and the Collateral Agent
45
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, 1994, from the Company in favor of the Collateral
Agent
10.10.19(1) Intercreditor Agreement, dated as of May 1, 1994, among the
Trustee, the Credit Bank, the Funding Corporation, the
Partnership, the Collateral Agent and certain other parties
10.10.20(1) Purchase Agreement and Transfer Supplement, dated as of May 1,
1994, among Chase, Dresdner, Yasuda, the Funding Corporation
and the Partnership
10.11 Other Material Project Contracts
10.11.1(1) Purchase Agreement, dated April 29, 1994, among the Funding
Corporation, the Partnership, CS First Boston Corporation,
Chase Securities, Inc. and Morgan Stanley & Co. Incorporated
46
10.11.2(1) Capital Contribution Agreement, dated as of April 28, 1994,
among the Partnership, JMC Selkirk, JMCS I Investors, Cogen
Technologies GP and Cogen Technologies LP (collectively, the
"Partners")
10.11.3(1) Equity Depositary Agreement, dated as of May 1, 1994, among the
Partnership, the Partners, Makowski Selkirk and Citibank, N.A.
as Special Agent
10.11.4(7) Master Restructuring Agreement, dated as of July 9, 1997, among
Niagara Mohawk, the Partnership and other Independent Power
Producers (defined therein)
16(16) Letter from former accountant (Arthur Andersen, LLP), dated as
of March 9, 1999, to the Securities and Exchange Commission
regarding the Partnership's change in certifying accountant
21(1) Subsidiaries of the Funding Corporation and Partnership
27 Financial Data Schedule (for electronic filing purposes only)
99 Additional Exhibits
99.1(12) Officer's Certificate of the Partnership, dated August 31,
1998, delivered to Bankers Trust Company, as Trustee
99.2(13) Independent Engineer's Certificate of R.W. Beck, Inc., dated as
of August 31, 1998, delivered to Bankers Trust Company, as
Trustee
99.3(14) Gas Consultant's Certificate of C.C. Pace Consulting, LLC,
dated August 28, 1998, delivered to Bankers Trust Company, as
Trustee
99.4(15) Press Release of the Partnership, dated August 31, 1998
- -----------------------
[FN]
(1) Incorporated herein by reference to the Registrant's Registration
Statement on Form S-1 filed September 1, 1994, as amended (File No. 33-83618).
(2) Incorporated herein by reference to the Registrant's Quarterly Report on
Form 10-Q for the Quarterly Period Ended June 30, 1995 filed August 14, 1995.
(3) Incorporated herein by reference to the Registrant's Quarterly Report on
Form 10-Q for the Quarterly Period Ended June 30, 1996 filed August 13, 1996.
47
(4) Incorporated herein by reference to the Registrant's Quarterly Report on
Form 10-Q for the Quarterly Period Ended September 30, 1996 filed November 14,
1996.
(5) Incorporated herein by reference to the Registrant's Quarterly Report on
Form 10-Q for the Quarterly Period Ended March 31, 1997 filed May 15, 1997.
(6) Incorporated herein by reference to the Registrant's Quarterly Report on
Form 10-Q for the Quarterly Period Ended June 30, 1997 filed August 14, 1997.
(7) Incorporated herein by reference to Exhibit Number 10.28 of the Current
Report on Form 8-K of Niagara Mohawk Power Corporation filed July 10, 1997.
(8) Incorporated herein by reference to Exhibit Number 10.1 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(9) Incorporated herein by reference to Exhibit Number 10.2 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(10) Incorporated herein by reference to Exhibit Number 10.3 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(11) Incorporated herein by reference to Exhibit Number 10.4 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(12) Incorporated herein by reference to Exhibit Number 99.1 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(13) Incorporated herein by reference to Exhibit Number 99.2 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(14) Incorporated herein by reference to Exhibit Number 99.3 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(15) Incorporated herein by reference to Exhibit Number 99.4 of the Registrant's
Current Report on Form 8-K filed September 16, 1998.
(16) Incorporated herein by reference to Exhibit Number 16 of the Registrant's
Current Report on Form 8-K filed March 9, 1999.
(17) Incorporated herein by reference to the Registrant's Annual Report on Form
10-K for the Fiscal Year Ended December 31, 1998 filed March 31, 1999.
</FN>
48
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 30, 2000 /s/ JMC SELKIRK, INC.
-----------------------
General Partner
Date: March 30, 2000 /s/ JOHN R. COOPER
--------------------
Name: John R. Cooper
Title: Senior Vice President and
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed by the following persons on behalf of the Registrant
in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ P. CHRISMAN IRIBE President and Director March 30, 2000
- ----------------------
P. Chrisman Iribe
/s/ SANFORD L. HARTMAN Director March 30, 2000
- -----------------------
Sanford L. Hartman
/s/ JOHN R. COOPER Senior Vice President and March 30, 2000
- ------------------- Chief Financial Officer
John R. Cooper
/s/ GARY F. WEIDINGER Senior Vice President March 30, 2000
- ----------------------
Gary F. Weidinger
/s/ DAVID N. BASSETT Treasurer March 30, 2000
- ---------------------
David N. Bassett
49
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 30, 2000 /s/ JOHN R. COOPER
--------------------
Name: John R. Cooper
Title: Senior Vice President and
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed by the following persons on behalf of the Registrant
in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ P. CHRISMAN IRIBE President and Director March 30, 2000
- ----------------------
P. Chrisman Iribe
/s/ SANFORD L. HARTMAN Director March 30, 2000
- -----------------------
Sanford L. Hartman
/s/ JOHN R. COOPER Senior Vice President and March 30, 2000
- ------------------- Chief Finanicla Officer
John R. Cooper
/s/ GARY F. WEIDINGER Senior Vice President March 30, 2000
- ----------------------
Gary F. Weidinger
/s/ DAVID N. BASSETT Treasurer March 30, 2000
- ---------------------
David N. Bassett
50