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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, 2000
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, 2001, 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..................................................... 1
Item 2. Properties................................................... 14
Item 3. Legal Proceedings............................................ 14
Item 4. Submission of Matters to a Vote of Security Holders.......... 16
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters........................................ 17
Item 6. Selected Financial Data...................................... 17
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................ 19
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............................................................ 50
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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 for the sale of electric capacity and energy produced by the
Facility with Niagara Mohawk Power Corporation ("Niagara Mohawk") and
Consolidated Edison Company of New York, Inc. ("Con Edison") and steam produced
by the Facility with 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.), Aquila Selkirk,
Inc. ("Aquila Selkirk", formerly EI Selkirk, Inc.) 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
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Partners, and principally the Managing General Partner, exercise control over
the Partnership. JMCS I Management, Inc. ("JMCS I Management"), an affiliate of
the Managing General Partner, is acting as the project management firm (the
"Project Management Firm") for the Partnership, and as such is responsible for
the implementation and administration of the Partnership's business under the
direction of the Managing General Partner. Upon the occurrence of certain events
specified in the Partnership Agreement, 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. PG&EGen Power is a direct, wholly-owned subsidiary of PG&E Generating
Company, LLC ("PG&EGen Company"), an indirect, wholly-owned subsidiary of PG&E
National Energy Group, Inc. ("NEG"). NEG is an indirect, wholly-owned subsidiary
of PG&E Corporation.
JMCS I Management is a direct, wholly-owned subsidiary of PG&E
Generating Services, LLC, a direct, wholly-owned subsidiary of PG&EGen Company,
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.).
Aquila Selkirk is a wholly-owned subsidiary of Aquila East Coast
Generation, Inc. ("Aquila ECG", formerly GPU International, Inc.) which is a
wholly-owned subsidiary of MEP Investments, LLC ("MEP"). MEP is an indirect
wholly-owned subsidiary of Aquila, Inc.("Aquila").
Because the California energy markets situation has caused financial
difficulties for Pacific Gas and Electric Company, a wholly-owned subsidiary of
PG&E Corporation, PG&E Corporation's credit ratings were downgraded to below
investment grade in January 2001, which caused PG&E Corporation to default on
outstanding commercial paper and bank borrowings. In January 2001, certain
corporate actions were taken to insulate the assets of NEG and its direct and
indirect subsidiaries from an effort to substantively consolidate those assets
in any insolvency or bankruptcy proceeding of PG&E Corporation. In March 2001,
PG&E Corporation refinanced all of its outstanding commercial paper and bank
borrowings, and Standard & Poors subsequently removed its below investment grade
credit rating since PG&E Corporation no longer had rated securities outstanding.
Management believes that the NEG and its direct and indirect subsidiaries as
described above, including JMC Selkirk,
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would not be substantively consolidated with PG&E Corporation in any insolvency
or bankruptcy proceeding involving PG&E Corporation.
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 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, Aquila, 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
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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, PG&E Energy Trading - Power, L.P.
("PG&E Energy Trading") and the New York Independent System Operator ("ISO") and
to produce useful thermal energy in the form of steam for sale to General
Electric for industrial purposes. The Facility is a "topping-cycle cogeneration
facility," which means that when the Facility is operated in a combined-cycle
mode, it uses natural gas or fuel oil to produce electricity, and the reject
heat from power production is then used to provide steam to General Electric.
Unit 1 and Unit 2 have been designed to operate independently for electrical
generation, while thermally integrated for steam generation, thereby optimizing
efficiencies in the combined performance of the Facility. A properly designed
and constructed cogeneration facility is able to convert the energy contained in
the input fuel source to useful energy outputs more efficiently than typical
utility plants. The Facility has been certified as a qualifying facility
("Qualifying Facility") in accordance with PURPA and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission ("FERC").
Niagara Mohawk
The Partnership has a long term contract with Niagara Mohawk for the
sale of electric capacity and energy produced by Unit 1 to Niagara Mohawk. For
the year ended December 31, 2000, 1999 and 1998, electric sales to Niagara
Mohawk accounted for approximately 18.7%, 19.5% and 19.7%, respectively, of
total project revenues.
Unit 1 commenced commercial operation on April 17, 1992 and through
June 30, 1998 sold at least 79.9 MW of electric capacity and associated energy
to Niagara Mohawk under the original long-term contract that allowed Niagara
Mohawk to schedule Unit 1 for dispatch on an economic basis (the "Original
Niagara Mohawk Power Purchase Agreement"). The term of the Original Niagara
Mohawk Power Purchase Agreement was 20 years from the date of initial commercial
operation of Unit 1. On August 31, 1998 the Partnership and Niagara Mohawk
executed an Amended and Restated Power Purchase Agreement dated as of July 1,
1998 (the "Amended and Restated Niagara Mohawk Power Purchase Agreement"). The
term of the Amended and Restated Niagara Mohawk Power Purchase Agreement is ten
years from July 1, 1998 (with the exception of certain transitional call and put
rights which were held by Niagara Mohawk and the Partnership (the "Transitional
Rights") and terminated on October 31, 2000, with respect to energy and capacity
sales).
In conjunction with the Amended and Restated Niagara Mohawk Power
Purchase Agreement, the Partnership and Niagara Mohawk also completed other
transactions pursuant to 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
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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 Niagara Mohawk Power Purchase
Agreement became effective and Niagara Mohawk made cash payments, representing
the Partnership's 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. These payments together with subsequent adjustment
payments made by Niagara Mohawk to the Partnership totaled $10.5 million.
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 Transitional Rights or
exercise by Niagara Mohawk of its right of first refusal described 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. On November 18,
1999, the 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
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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.
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 are subject to
Niagara Mohawk's right of first refusal, 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
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Niagara Mohawk owns, operates and maintains interconnection facilities
for the combined Facility in accordance with separate Unit 1 and Unit 2
interconnection agreements. The Unit 1 interconnection facility is necessary to
effect the transfer of electricity produced at Unit 1 into Niagara Mohawk's
power grid at the delivery point adjacent to Unit 1. Since Unit 1 is
interconnected directly to Niagara Mohawk's power grid, no transmission services
are required for the delivery of power under the Amended and Restated Niagara
Mohawk Power Purchase Agreement. The Unit 2 interconnection facility is
necessary to effect the transfer of electricity produced at Unit 2 into Niagara
Mohawk's transmission system. Pursuant to a 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
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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, 2000, 1999 and 1998 electric
sales to Con Edison accounted for approximately 61.5%, 68.1% and 71.1%,
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 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
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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
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, 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, 2001 and the Partnership intends to renew the Enabling Agreement through May
2002. 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,
2000, 1999 and 1998, sales to PG&E Energy Trading accounted for approximately
6.4%, 3.3% and 1.2%, respectively, of total project revenues.
New York Independent System Operator
The ISO commenced operation on November 18, 1999 and took formal
control of the New York wholesale electric power system on December 1, 1999. The
ISO administers markets in energy, installed capacity and ancillary services for
the New York control area and operates the bulk power transmission system in New
York. Energy transactions in New York may involve sales and purchases to and
from the ISO in the ISO-administered markets, or bilateral transactions between
participants in the New York wholesale market. PG&E Energy Trading and the
Partnership are active participants in these markets. For the year ended
December 31, 2000 sales to the ISO accounted for approximately 0.1% of total
project revenues.
General Electric
Pursuant to a steam sales agreement with General Electric (the "Steam
Sales Agreement"), the Partnership is obligated to sell up to 400,000 lbs/hr of
the thermal output of Unit 1 and Unit 2 for use as process steam at the GE Plant
adjacent to the Facility for a term extending 20 years from the date of
commercial operations of Unit 2. The Partnership charges General Electric a
nominal price for steam delivered to General Electric in an amount up to the
annual equivalent of 160,000 lbs/hr during each hour in which the GE Plant is in
production (the "Discounted Quantity"). Steam sales in excess of the Discounted
Quantity are priced at General Electric's avoided variable direct cost, subject
to an "annual true-up" to ensure that General Electric receives the annual
equivalent of the Discounted Quantity at nominal pricing.
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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, 2000, 1999 and 1998, sales to General
Electric accounted for approximately 1.1%, 0.5% and 0.0%, 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
remains unchanged, and the maximum daily quantity of natural gas which the
Partnership is entitled to purchase is 16,400 Mcf. The Amended Paramount
Contract requires Paramount to maintain a level of recoverable reserves and
deliverability from its dedicated reserves through the term of the Amended
Paramount Contract. Paramount must demonstrate that it meets the recoverable
reserves and deliverability requirements in an annual report to the Partnership.
The Partnership entered into certain long-term contracts (collectively,
the "Unit 1 Gas Transportation Contracts") for the transportation of the Unit 1
natural gas volumes on a firm 365-day per year basis with TransCanada Pipelines
Limited ("TransCanada"), Iroquois Gas Transmissions System, L.P. ("Iroquois")
and Tennessee Gas Pipeline Company ("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"),
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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 "gas resales", "gas optimizations" and "peak shaving
arrangements". Gas resales are sales of excess natural gas supplies when Unit 1
or Unit 2 is dispatched off-line or at less than full capacity. Gas
optimizations are opportunities whereby the Partnership is able to optimize the
long-term gas supply and transportation contracts and lower the cost of natural
gas delivered to the Facility by purchasing and/or selling natural gas at
favorable prices along the transportation route. Peak shaving are arrangements
whereby the Partnership grants to local distribution companies or other
purchasers a call on a specified portion of the Partnership's firm natural gas
supply for a specified number of days during the winter season. At such times as
the purchaser calls upon the Partnership's firm natural gas supply under a peak
shaving arrangement, the Partnership intends to operate on No. 2 fuel oil or, if
available, interruptible natural gas supplies. Typically, the Partnership's
liability for failure to deliver natural gas when called for under a peak
shaving agreement is to reimburse the purchaser for its prudently incurred
incremental costs of finding a replacement supply of natural gas. The
Partnership attempts to schedule firm gas transportation services to meet its
requirements to fuel Unit 1 and Unit 2 and to meet its gas resales, gas
optimizations 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, gas optimizations 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. For the year ended December 31, 2000, 1999 and
1998, fuel revenues accounted for approximately 12.2%, 8.6% and 8.0% ,
respectively, of total project revenues.
-10-
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 910 thousand 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 purchase,
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 purchase and/or
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.
The ISO is a not-for-profit organization engaged in facilitating fair
and open competition in the wholesale power market and creates an electricity
commodity market in which power is purchased and sold on the basis of
competitive bidding.
GE Plastics, a core business of General Electric, manufactures
high-performance engineered plastics used in applications such as automobiles,
housings for computers and other business equipment. GE Plastics sells worldwide
to a diverse customer base consisting mainly of manufacturers.
The demand for power in the United States traditionally has been met by
utility construction of large-scale electric generation projects under rate-base
regulation. PURPA removed certain regulatory constraints relating to the
production and sale of electric energy by eligible non-utilities and required
electric utilities to buy electricity from various types of non-utility power
producers under certain conditions, thereby encouraging companies other than
electric utilities to enter the electric power production market. Concurrently,
there has been a decline in the construction of large generating plants by
electric utilities. In addition to independent power producers, subsidiaries of
fuel supply companies, engineering companies, equipment manufacturers and other
industrial companies, as well as subsidiaries of regulated utilities, have
entered the non-utility power market. The Partnership has a long-term
-11-
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, 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 purchasers' customer and market
demand results in the Facility's dispatch being somewhat affected by
seasonality. Niagara Mohawk's residential customer demand peaks during the
colder winter months due to customer reliance on electric heat, and Con Edison's
commercial customer demand peaks during the warmer summer months due to customer
reliance on air conditioning in office buildings. In addition, the gas resale
market is also somewhat seasonal in nature, with the cold winter months tending
to drive up the price of natural gas.
Regulations and Environmental Matters
The Partnership must sell an aggregate annual average of approximately
80,000 lbs/hr from Unit 1 and Unit 2 combined for use as process steam by
General Electric and must satisfy other operating and ownership criteria in
order to comply with the requirements for a Qualifying Facility under PURPA. If
the Facility were to fail to meet such criteria, the Partnership may become
subject to regulation as a subsidiary of a holding company, a public utility
company or an electric utility company under PUHCA, the Federal Power Act (the
"FPA") and state utility laws. If the Facility loses its Qualifying Facility
status, its Power Purchase Agreements will be subject to the jurisdiction of the
FERC under the FPA. The Partnership may nevertheless be exempt from regulation
under PUHCA if it maintains "exempt wholesale generator" status. In 1994, the
Partnership filed with the FERC an Application for Determination of Exempt
Wholesale Generator Status, which was granted by the FERC.
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
-12-
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.
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
-13-
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 a
Second 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 30 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.
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.
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
-14-
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
In 1999, Niagara Mohawk and other New York transmission owning
companies (the "Member Systems") initiated a proceeding at the FERC to amend the
transmission agreements of a number of New York independent power producers,
including the Partnership. The proposed amendments were intended to reconcile
the rates, terms and conditions of certain existing transmission agreements with
the restructured ISO-administered markets. The Partnership intervened in the
Member Systems' proceeding at the FERC to protest Niagara Mohawk's proposed
amendments to the transmission services agreement for Unit 2 (the "Transmission
Services Agreement'). The Partnership's protest was settled by the parties in
two stipulations which were approved by the FERC on August 1, 2000 and October
26, 2000, respectively. Among other things, it was agreed in the settlement
among the ISO, the Partnership and the other parties to the proceeding, that the
Partnership would be deemed to comply with the energy balancing provisions of
the ISO tariffs for power sales to parties other than the ISO, provided that any
imbalance would be the responsibility of the power purchasers for the purposes
of the ISO tariffs. The Partnership and the other parties to this proceeding
also agreed to changes in the terms and operation of the ISO's tariffs, as they
affect the Transmission Service Agreement, and agreed that the tariffs would
otherwise apply to the Partnership and the Transmission Service Agreement to the
extent consistent with the existing provisions of the agreement, as amended.
A key issue in the Member Systems' proceeding involved whether
compliance with the energy balancing provisions of the ISO's tariffs, as
required under the proposed amendments to the existing Transmission Service
Agreement, would undermine the Partnership's status as a Qualifying Facility. On
March 9, 2000, the FERC responded to a certified question concerning this issue
submitted by certain parties in the negative, thus preserving the Partnership's
ability to make sales to the ISO without losing its status as a Qualifying
Facility.
As part of the settlement of the Member Systems' proceeding, the ISO
agreed to file a tariff amendment exempting the Partnership and other similarly
situated generators from regulation penalties, provided market participants
supported the exemption. While the ISO has not filed such a tariff amendment nor
charged the Partnership for regulation penalties, the ISO announced in March
2001 a decision to exempt Qualifying Facilities and certain other generators
from the regulation provisions.
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
-15-
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.
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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. Certain reclassifications
have been made to the selected financial data and supplementary financial
information set forth below to reflect new accounting pronouncements as
discussed in Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.
Year Ended December 31,
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
Statement of Operations
Data:
Operating revenues $234,377 $177,468 $172,739 $184,111 $182,971
Cost of revenues 163,389 117,331 119,240 133,833 128,276
Other operating expenses 5,541 4,553 5,130 6,584 6,669
Operating income 65,447 55,584 48,369 43,694 48,026
Net interest expense 30,899 31,687 32,048 32,234 32,844
---------- --------- --------- ---------- ---------
Income before cumulative
effect of a change in
accounting principle 34,548 23,897 16,321 11,460 15,182
Cumulative effect of a change
in accounting principle 7,866 --- --- --- ---
----- ------ ------ ------ ------
Net income $ 42,414 $ 23,897 $ 16,321 $ 11,460 $ 15,182
======== ======== ======== ======== ========
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December 31,
------------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
Balance Sheet Data:
Plant and equipment, net $285,324 $297,034 $308,999 $321,537 $334,229
Total assets 358,942 367,087 373,877 385,874 401,454
Long-term bonds,
net of current portion 362,764 373,826 381,133 385,955 389,253
Partners' deficits (49,646) (50,832) (46,810) (32,282) (18,810)
Supplementary Financial Information
The following is a summary of the quarterly results of operations for
the years ended December 31, 1998, December 31, 1999 and December 31, 2000.
Three Months Ended (unaudited)
---------------------------------------------------------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
(in thousands)
Year Ended
December 31, 1998
- --------------------
Operating revenues $ 45,377 $ 43,152 $ 43,856 $ 40,354
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 $ 43,922 $ 41,013 $ 48,966 $ 43,567
Gross Profit 17,218 11,182 17,204 14,533
Net income 8,196 2,003 8,088 5,610
Year Ended
December 31, 2000
- --------------------
Operating revenues $ 60,585 $ 52,270 $ 56,763 $ 64,759
Gross Profit 19,820 14,326 19,032 17,810
Income before cumulative
effect of a change in
accounting principle 10,673 5,119 9,679 9,077
Cumulative effect of a change
in accounting principle 7,866 --- --- ---
Net income 18,539 5,119 9,679 9,077
-18-
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 $42.4 million,
$23.9 million and $16.3 million in 2000, 1999 and 1998, respectively, and made
cash distributions to the partners of approximately $41.2 million, $27.9 million
and $30.8 million in 2000, 1999 and 1998, respectively.
New Accounting Pronouncements
The Partnership will adopt Statement of Financial Accounting Standards
("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities,
as amended by SFAS Nos. 137 and 138, on January 1, 2001. This standard requires
the Partnership to recognize all derivatives, as defined in the Statement, on
the balance sheet at fair value. Derivatives, or any portion thereof, that are
not designated and effective hedges must be adjusted to fair value through
income. If derivatives are effective hedges, depending on the nature of the
hedges, changes in the fair value of derivatives either will offset the change
in fair value of the hedged assets, liabilities, or firm commitments through
earnings, or will be recognized in other comprehensive income until the hedged
items are recognized in earnings. The Partnership estimates that the transition
adjustment to implement this new standard will not effect net income and will be
a negative adjustment of approximately $9.0 million to other comprehensive
income, a component of partners' equity. The Partnership also has certain
derivative commodity contracts for the physical delivery of purchase and sale
quantities transacted in the normal course of business. At this time, these
derivatives are exempt from the requirements of SFAS No. 133 under the normal
purchases and sales exception, and thus will not be reflected on the balance
sheet at fair value. The Derivative Implementation Group of the Financial
Accounting Standards Board is currently evaluating the definition of normal
purchases and sales. As such, certain derivative commodity contracts may no
longer be exempt from the requirements of SFAS No. 133. When the final decision
regarding this issue is complete, the Partnership will evaluate the impact of
the implementation guidance on a prospective basis.
Staff Accounting Bulletin No. 101, Revenue Recognition ("SAB No. 101")
was issued by the Staff of the Securities and Exchange Commission ("SEC") on
December 3, 1999. SAB No. 101, as amended, summarizes certain of the SEC staff's
views in applying generally accepted accounting principles to revenue
recognition in financial statements. In addition, the Emerging Issues Task Force
("EITF") issued EITF Issue No. 99-19, Reporting Revenue Gross as a Principal
versus Net as an Agent. The Partnership adopted these related accounting
pronouncements in 2000, resulting in a change in the method of reporting the
Partnership's
-19-
fuel revenue. As a result of the reporting change and the reclassification of
prior periods for comparison purposes, all of the Partnership's revenues from
the sale of gas are reported gross as operating revenue for all periods
presented. The change had no effect on the Partnership's net income or partners'
capital, but increased its revenues and fuel costs.
Results of Operations
Year Ended December 31, 2000 Compared to the Year Ended December 31, 1999
The Partnership earned net income of approximately $42.4 million for
the year ended December 31, 2000 as compared to net income of approximately
$23.9 million for the prior year. The $18.5 million increase in net income is
primarily due to higher operating revenues and the Partnership changing its
method of accounting for major maintenance and overhaul costs.
Effective January 1, 2000, the Partnership changed its method of
accounting for major maintenance and overhaul costs to expensing the cost of
major maintenance and overhauls as incurred. Prior to January 1, 2000, the
estimated cost of major maintenance and overhauls was accrued in advance based
on projected future cost of major maintenance and overhaul using the
straight-line method over the period between major maintenance and overhaul. The
Partnership implemented the new accounting method by recording the cumulative
effect of a change in accounting principle in the consolidated statement of
operations for the year ended December 31, 2000. The cumulative effect of
adopting the new accounting principle was the recording of net income totaling
$7.9 million on January 1, 2000. The effect on results of operations for the
year ended December 31, 2000 was an increase of other operating and maintenance
expense of approximately $0.8 million. If the cumulative effect had been
recorded in 1998 or 1999, then the pro forma effect (unaudited) for 1998 and
1999 would have increased net income by approximately $1.4 million and $1.3
million, respectively.
Total revenues for the year ended December 31, 2000 were approximately
$234.4 million as compared to approximately $177.5 million for the prior year.
Electric Revenues (dollars and kWh's in millions):
For the Year Ended
December 31, 2000 December 31, 1999
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ----- -------- --------
Unit 1 58.9 617.1 88.60% 95.67% 40.1 510.7 74.67% 85.56%
Unit 2 144.0 1,835.8 78.87% 87.85% 121.2 1,752.1 75.28% 81.37%
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.
-20-
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 $18.8 million for the year
ended December 31, 2000 as compared to the prior year. During the year ended
December 31, 2000, revenues from Niagara Mohawk, PG&E Energy Trading and the New
York ISO were approximately $43.8 million, $14.9 million and $0.2 million as
compared to approximately $34.6 million, $5.5 million and $0.0 million,
respectively, for the prior year. The increase in Unit 1 revenues for the year
ended December 31, 2000 was primarily due to increases in Monthly Contract
Payments, market energy prices and volume of delivered energy. 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 years
ended December 31, 2000 and 1999, with the exception of the months of April
2000, April 1999 and October 1999, the Partnership received Monthly Contract
Payments from Niagara Mohawk. During the years ended December 31, 2000 and 1999,
with the exception of the months of April 2000, November 2000, December 2000,
April 1999 and October 1999, the Partnership delivered energy up to the monthly
contract quantity to Niagara Mohawk ("Contract Energy"). Effective with the
termination of Transitional Rights on October 31, 2000, Niagara Mohawk is no
longer obligated to purchase Contract Energy. Commencing on November 18, 1999,
Contract Energy was sold at market prices established by the New York
Independent System Operator. During the period from January 1, 1999 through
November 17, 1999, Contract Energy was sold at a proxy market price based upon
Niagara Mohawk's tariff for power purchases from Qualifying Facilities. During
the months of May, June, July, August, September and October 2000, the
Partnership sold all of the energy produced by Unit 1 in excess of the Contract
Energy ("Unit 1 Excess Energy") to PG&E Energy Trading. During the months of
January and March 2000 the Partnership sold the Unit 1 Excess Energy to both
Niagara Mohawk and PG&E Energy Trading, and during the month of February 2000,
the Partnership sold all of the Unit 1 Excess Energy to Niagara Mohawk. During
the months of April, November and December 2000, the Partnership sold all of the
energy produced by Unit 1 to PG&E Energy Trading. During the month of January
1999, the Partnership sold all of the Unit 1 Excess Energy to Niagara Mohawk.
During the months of February, March, June and September 1999, the Partnership
sold all of the Unit 1 Excess Energy to PG&E Energy Trading. During the months
of May, July, August, November and December 1999, the Partnership sold Unit 1
Excess Energy to both Niagara Mohawk and PG&E Energy Trading. During the month
of April 1999, the Partnership sold all of the energy produced by 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. Unit 1 Excess Energy delivered
to Niagara Mohawk and PG&E Energy Trading was sold at negotiated market prices.
During the year ended December 31, 2000, revenues from the New York ISO resulted
from sales of installed capacity in excess of contract amounts due under the
Amended and Restated Niagara Mohawk Power Purchase Agreement. Amortized deferred
revenues of approximately $0.7 million are also included in revenues from
Niagara Mohawk for each of the years ended December 31, 2000 and 1999.
-21-
Revenues from Unit 2 increased approximately $22.8 million for the year
ended December 31, 2000 as compared to the prior year. During the year ended
December 31, 2000, Unit 2 revenues from Con Edison and PG&E Energy Trading were
approximately $144.0 million and $0.0 million as compared to approximately
$120.9 million and $0.3 million, respectively, for the prior year. The increase
in revenues from Unit 2 for the year ended December 31, 2000 was primarily due
to the increase in the Con Edison contract price for delivered energy resulting
from higher index fuel prices. During the year ended December 31, 1999, Unit 2
revenues from PG&E Energy Trading resulted from the sale of other energy-related
products.
Steam revenues for the years ended December 31, 2000 and 1999 of
approximately $2.6 million and $1.1 million, respectively, were reduced by a
reserve of approximately $51.0 thousand and $245.0 thousand, respectively, 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. Delivered steam for the
year ended December 31, 2000 was approximately 1.8 billion pounds as compared to
approximately 1.6 billion pounds in the prior year. The increase in steam
revenues for the year ended December 31, 2000 was primarily due to the increase
in the General Electric contract price for delivered steam resulting from the
higher index fuel prices.
Fuel revenues for the year ended December 31, 2000 were approximately
$28.8 million as compared to $15.4 million for the prior year. Gas resale
revenues for the year ended December 31, 2000 were approximately $15.2 million
on sales of approximately 3.6 million MMBtu's as compared to approximately $10.9
million on sales of approximately 4.4 million MMBtu's for the prior year. The
$4.3 million increase in gas resale revenues during the year ended December 31,
2000 is primarily due to higher natural gas resale prices. The increase in
natural gas resale prices during the year ended December 31, 2000 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. Gas optimization revenues for the year
ended December 31, 2000 were approximately $11.5 million on sales of
approximately 3.6 million MMBtu's as compared to approximately $3.6 million on
sales of approximately 1.4 million MMBtu's for the prior year. Gas optimizations
occur when the Partnership is able to optimize the long-term supply and
transportation contracts and lower the cost of natural gas delivered to the
Facility by purchasing and/or selling natural gas at favorable prices along the
transportation route. Revenues from peak shaving arrangements for the year ended
December 31, 2000 were approximately $2.1 million on sales of approximately 182
thousand MMBtu's as compared to approximately $0.8 million on sales of
approximately 24 thousand MMBtu's for the prior year. Peak shaving arrangements
occur when the Partnership grants 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.
Fuel and transmission costs for the year ended December 31, 2000 were
approximately $134.3 million as compared to approximately $87.2 million for the
prior year. Fuel costs, excluding the cost of fuel associated with gas
optimizations and peak shaving arrangements, for the year ended December 31,
2000 were approximately $115.2 million on purchases of approximately 28.3
million MMBtu's as compared to approximately $78.0 million on purchases of
-22-
approximately 27.8 million MMBtu's for the prior year. The $37.2 million
increase in the cost of fuel was primarily due to the higher price of gas under
the firm fuel supply contracts, higher demand costs under the firm fuel
transportation contracts and additional gas import tax of approximately $1.0
million resulting from the settlement of a gas import tax audit. Additionally,
fuel costs during the year ended December 31, 1999 were reduced by the write-off
of reserves of approximately $1.4 million for amounts no longer in dispute with
gas suppliers and transporters. Fuel costs associated with gas optimizations for
the year ended December 31, 2000 were approximately $10.7 million on purchases
of approximately 3.6 million MMBtu's as compared to approximately $3.6 million
on purchases of approximately 1.4 million MMBtu's. Fuel costs associated with
peak shaving arrangements for the year ended December 31, 2000 were
approximately $0.8 million on purchases of 182 thousand MMBtu's as compared to
$0.1 million on purchases of 24 thousand MMBtu's for the prior year. 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, 2000 and
1999, fuel costs were increased by approximately $2.5 million and $2.3 million,
respectively, as a result of the currency swap agreements. Transmission costs
for the years ended December 31, 2000 and 1999 were approximately $7.6 million
and $5.6 million, respectively.
Other operating and maintenance expenses for the year ended December
31, 2000 were approximately $16.6 million as compared to approximately $17.7
million for the prior year. The $1.1 million decrease in other operating and
maintenance expenses was primarily due to differences in the scheduling of
planned maintenance and the elimination of the accrual for major maintenance and
overhaul costs.
Total other operating expenses, excluding amortization of deferred
financing charges, for the year ended December 31, 2000 were approximately $4.4
million as compared to approximately $3.4 million for the prior year. The $1.0
million increase in other operating expenses, excluding amortization of deferred
financing charges, was primarily due to higher affiliate administrative services
and higher property insurance premiums. Additionally, affiliate administrative
services during the year ended December 31, 1999 were reduced by the write-off
of a reserve of approximately $0.2 million for amounts no longer claimed by an
affiliate.
Amortization of deferred financing charges of approximately $1.1
million for the year ended December 31, 2000 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, 2000 was
approximately $30.9 million as compared to approximately $31.7 million for the
prior year. The decrease in net interest expense was due to higher interest
income and lower bond interest expense resulting from the lower principal
balance outstanding, partially offset by higher interest expense associated with
the settlement of a gas import tax audit.
-23-
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
$177.5 million as compared to approximately $172.7 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%
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 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.
-24-
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
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.
Fuel revenues for the year ended December 31, 1999 were approximately
$15.4 million as compared to $13.9 million for 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
-25-
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. Gas optimization revenues
for the year ended December 31, 1999 were approximately $3.7 million on sales of
approximately 1.4 million MMBtu's as compared to approximately $6.2 million on
sales of approximately 2.4 million MMBtu's for the prior year. Gas optimizations
occur when the Partnership is able to optimize the long-term supply and
transportation contracts and lower the cost of natural gas delivered to the
Facility by purchasing and/or selling natural gas at favorable prices along the
transportation route. Revenues from peak shaving arrangements for the year ended
December 31, 1999 were approximately $0.8 million on sales of approximately 24
thousand MMBtu's as compared to approximately $0.5 million on sales of
approximately 0 MMBtu's for the prior year. Peak shaving arrangements occur when
the Partnership grants 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.
Fuel and transmission costs for the year ended December 31, 1999 were
approximately $87.2 million as compared to approximately $89.1 million for the
prior year. Fuel costs, excluding the cost of fuel associated with gas
optimizations and peak shaving arrangements, for the year ended December 31,
1999 were approximately $78.0 million on purchases of approximately 27.8 million
MMBtu's as compared to approximately $77.5 million on purchases of approximately
28.2 million MMBtu's for the prior year. The $0.5 million increase was primarily
due to the higher price of gas under the firm fuel supply 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. Fuel costs associated
with gas optimizations for the year ended December 31, 1999 were approximately
$3.5 million on purchases of approximately 1.4 million MMBtu's as compared to
approximately $6.0 million on purchases of approximately 2.4 million MMBtu's.
Fuel costs associated with peak shaving arrangements for the year ended December
31, 1999 were approximately $0.1 million on purchases of 24 thousand MMBtu's as
compared to $0 on purchases of 0 MMBtu's for the prior year. 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. Transmission costs were approximately
$5.6 million in each of the years ended December 31, 1999 and 1998.
Other operating and maintenance expenses for the year ended December
31, 1999 of approximately $17.7 million were comparable to the prior year.
-26-
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.
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.
Liquidity and Capital Resources
Net cash provided by operating activities for the year ended December
31, 2000 was approximately $52.1 million as compared to approximately $33.3
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 used in investing activities for the year ended December 31,
2000 was approximately $0.8 million as compared to approximately $0.5 million
for the prior year. Net cash flows used in investing activities primarily
represent net additions to plant and equipment.
Net cash used in financing activities for the year ended December 31,
2000 was approximately $49.8 million as compared to approximately $32.9 million
for the prior year. The increase in net cash used in financing activities for
the year ended December 31, 2000 was primarily due to more cash becoming
available to deposit into restricted funds, more cash becoming available to
distribute to the Partners and the increase in the semi-annual payment of
principal on long-term debt. Pursuant to the Partnership's Deposit 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, 2000
and 1999 primarily represent deposits of monies into the Debt Service Reserve
Fund, cash distributions to Partners and payments of principal on long-term
debt.
The debt service coverage ratio for 2000 calculated pursuant to the
Indenture was 1.99:1.
-27-
Credit Agreement
The Partnership has available for its use a $7.5 million Credit
Agreement ("Credit Agreement"), which is to be used by the Partnership for
required letters of credit related to various project contracts and for working
capital purposes. The maximum amount available under the Credit Agreement for
working capital purposes is $5.0 million. At December 31, and 1999, 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 8, 2003.
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, 2000,
the balance in this Fund was approximately $3.9 million. During the year ending
December 31, 2001, deposits of approximately $3.3 million 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, 2000, 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, 2000. The June 26, 2001 Interest and Principal
Fund Requirements will be approximately $16.5 million and approximately $6.0
million, respectively.
-28-
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, 2000, the balance in this Fund was approximately $24.0 million. The
June 26, 2001 Fund Requirement will remain at approximately $24.0 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, 2001
During 2001, the Partnership anticipates Con Edison to dispatch the
Unit 2 at levels consistent with the prior year. 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
continue to 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 2001, 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 2000 levels for the balance of 2001.
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.
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; and whether Con Edison were to prevail in its claim to
Unit 2's excess natural gas volumes.
-29-
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Partnership is exposed to market risk from changes in interest
rates, foreign currency exchange rates and energy commodity prices, 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 2000 interest rates would
have resulted in a negative impact of approximately $0.3 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 meet the terms of the agreements, the
Partnership's exposure is limited to the currency exchange rate differential.
During the year ended December 31, 2000, the exchange rate differential had a
negative impact of approximately $2.5 million on the Partnership's net income.
See Notes 5 and 6 to the Consolidated Financial Statements.
Energy Commodity Prices
The Partnership seeks to reduce its exposure to market risk associated
with energy commodities such as electric power and natural gas through the use
of long-term purchase and sale contracts. As part of its fuel management
activities, the Partnership also enters into agreements to resell its long-term
natural gas volumes, when it is feasible to do so, at favorable prices relative
to the cost of contract volumes and the cost of substitute fuels. To the extent
the Partnership has open positions, it is exposed to the risk that fluctuating
market prices may adversely impact its financial results.
-30-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- ----------------------------------------------------
The financial statements and supplementary data required by this item
are presented under Item 14 and are incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
- ---------------------------------------------------------
None.
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 Aquila ECG, Holdings may elect at least four members, and Aquila
ECG 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............... 50 President and Director
Sanford L. Hartman.............. 47 Director
John R. Cooper.................. 53 Senior Vice President and Chief
Financial Officer
Ernest K. Hauser............... 51 Senior Vice President
David N. Bassett............... 54 Treasurer
Managing General Partner:
- ------------------------
Name Age Position
---- --- --------
P. Chrisman Iribe............... 50 President and Director
Sanford L. Hartman.............. 47 Director
John R. Cooper.................. 53 Senior Vice President and Chief
Financial Officer
Ernest K. Hauser................ 51 Senior Vice President
David N. Bassett................ 54 Treasurer
P. Chrisman Iribe is President and Chief Operating Officer of PG&E
National Energy Group Company , formerly PG&E Generating Company, an affiliate
of the Partnership, and
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has been with PG&E National Energy Group Company since it was formed in 1989.
Prior to joining PG&E National Energy Group Company, 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 Vice President, General Counsel and Secretary of
PG&E National Energy Group Company, and has been with PG&E National Energy Group
Company since 1990. Mr. Hartman assumed the role of General Counsel in April
1999. Prior to joining PG&E National Energy Group Company, 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 Financial Officer of
PG&E National Energy Group Company, and has been with PG&E National Energy Group
Company, since it was formed in 1989. Prior to joining PG&E National Energy
Group Company, he spent three years as Chief Financial Officer with 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.
Ernest K. Hauser is Senior Vice President, Asset Management - Northeast
of PG&E National Energy Group Company, an affiliate of the Partnership, and has
been with PG&E National Energy Group Company since 1989. Mr. Hauser is
responsible for all PG&E National Energy Group Company business activities in
the Northeast. Prior to his present assignment, he was regional vice president
for marketing, development and asset management. Prior to joining PG&E National
Energy Group Company, Mr. Hauser was project director for co-generation and
alternative fuel technology projects at Coastal Power Production. He also worked
for more than ten years as energy project manager and senior engineer for the
Combustion Engineering family of companies.
David N. Bassett is Vice President, Controller and Treasurer of PG&E
National Energy Group Company, and has been with PG&E National Energy Group
Company 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 National Energy Group Company or certain of its affiliates play a role.
Prior to joining PG&E National Energy Group Company, 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. Aquila ECG is entitled to name
a designee to participate on a non-voting basis in meetings of the Management
Committee.
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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, 2000 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.**(5) General Partner (i) 1.0000%
711 Louisiana Street (iii) .2211%
Houston, Texas 77002
Partnership Interest RCM Selkirk LP, Inc.***(5) Limited Partner (i) 78.1557%
711 Louisiana Street (iii) 17.2789%
Houston, Texas 77002
Partnership interest Aquila Selkirk, Inc.****(6) Limited Partner (i) 13.5523%
One Upper Pond Road (ii) 20.0000%
Parsippany, New Jersey 07054 (iii) 17.7000%
* Formerly JMCS I Investors, L.P.
** Formerly Cogen Technologies GP, Inc.
*** Formerly Cogen Technologies LP, Inc.
**** Formerly EI Selkirk, 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 Aquila 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) Aquila Selkirk is a wholly-owned subsidiary of Aquila ECG.
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 years ended December 31, 2000
and 1999......................................................... F-1
Report of Independent Public Accountants for the year ended
December 31, 1998................................................ F-2
Consolidated Balance Sheets as of December 31, 2000 and 1999..... F-3
Consolidated Statements of Operations for the years ended
December 31, 2000, 1999 and 1998................................. F-4
Consolidated Statements of Changes in Partners' Deficits for the
years ended December 31, 2000, 1999 and 1998...................... F-5
Consolidated Statements of Cash Flows for the years ended
December 31, 2000, 1999 and 1998.................................. 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 sheets of Selkirk Cogen
Partners, L.P. (a Delaware limited partnership) and its subsidiary
(collectively, the "Partnership") as of December 31, 2000 and 1999, 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 financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. 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, such financial statements present fairly, in all material
respects, the financial position of the Partnership as of December 31, 2000 and
1999, and the results of its operations and its cash flows for the years then
ended, in conformity with accounting principles generally accepted in the United
States of America.
As discussed in Note 2 to the financial statements, in 2000 the Partnership
changed its method of accounting for major maintenance and overhaul costs.
/s/ DELOITTE & TOUCHE LLP
- -------------------------
McLean, Virginia
March 16, 2001
F-1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners of Selkirk Cogen Partners, L.P.:
We have audited the accompanying consolidated statement of operations and cash
flows for the year ended December 31, 1998. These consolidated statements are
the responsibility of the Partnership's management. Our responsibility is to
express an opinion on these consolidated statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. 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 results of
operations and cash flows of Selkirk Cogen Partners, L.P. and its subsidiary for
the year ended December 31, 1998, in conformity with accounting principles
generally accepted in the United States.
/s/ ARTHUR ANDERSEN LLP
- -----------------------
Washington, D.C.
January 12, 1999
F-2
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2000 AND 1999
(In Thousands)
- -------------------------------------------------------------------------------
ASSETS 2000 1999
CURRENT ASSETS:
Cash and cash equivalents $ 3,187 $ 1,732
Restricted funds 2,988 5,516
Accounts receivable, net of allowance of $174 in 2000 20,097 15,505
Due from affiliates 3,882 427
Fuel inventory and supplies 6,693 6,831
Other current assets 436 195
--------- ---------
Total current assets 37,283 30,206
PLANT AND EQUIPMENT:
Plant and equipment, at cost 372,443 371,690
Less: Accumulated depreciation 87,119 74,656
--------- ----------
Plant and equipment, net 285,324 297,034
--------- ----------
LONG-TERM RESTRICTED FUNDS 27,833 30,217
DEFERRED FINANCING CHARGES, net of accumulated
amortization of $7,789 and $6,652 in
2000 and 1999, respectively 8,502 9,630
---------- ----------
TOTAL ASSETS $ 358,942 $ 367,087
========== ==========
LIABILITIES AND PARTNERS' DEFICITS
CURRENT LIABILITIES:
Accounts payable $ 49 $ 2,126
Accrued expenses 21,524 13,114
Due to affiliates 635 469
Current portion of long-term bonds 11,062 7,307
---------- ----------
Total current liabilities 33,270 23,016
LONG-TERM LIABILITIES:
Deferred revenue 5,304 5,981
Other long-term liabilities 7,250 15,096
Long-term bonds - net of current portion 362,764 373,826
---------- ----------
Total liabilities 408,588 417,919
---------- ----------
COMMITMENT AND CONTINGENCIES
PARTNERS' DEFICITS:
General partners' deficits (485) (497)
Limited partners' deficits (49,161) (50,335)
----------- ----------
Total partners' deficits (49,646) (50,832)
----------- ----------
TOTAL LIABILITIES AND PARTNERS' DEFICITS $ 358,942 $ 367,087
========== ==========
See notes to consolidated financial statements.
F-3
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(In Thousands)
- -----------------------------------------------------------------------------------------------------------------------
2000 1999 1998
OPERATING REVENUES:
Electric and steam $ 205,539 $ 162,111 $ 158,805
Fuel revenues 28,838 15,357 13,934
---------- ---------- ---------
Total operating revenues 234,377 177,468 172,739
COST OF REVENUES:
Fuel and transmission costs 134,272 87,226 89,145
Other operating and maintenance 16,649 17,652 17,594
Depreciation 12,468 12,453 12,501
---------- ---------- ---------
Total cost of revenues 163,389 117,331 119,240
---------- ---------- ---------
GROSS PROFIT 70,988 60,137 53,499
---------- ---------- ---------
OTHER OPERATING EXPENSES:
Administrative services, affiliates 2,244 1,802 1,931
Other general and administrative 2,169 1,599 2,036
Amortization of deferred financing charges 1,128 1,152 1,163
---------- ---------- ---------
Total other operating expenses 5,541 4,553 5,130
---------- ---------- ---------
OPERATING INCOME 65,447 55,584 48,369
INTEREST (INCOME) EXPENSE:
Interest income (3,176) (2,355) (2,298)
Interest expense 34,075 34,042 34,346
---------- ---------- ---------
Total interest expense, net 30,899 31,687 32,048
Income before cumulative effect of a change
in accounting principle 34,548 23,897 16,321
Cumulative effect of a change in
accounting principle 7,866
---------- ---------- ---------
NET INCOME $ 42,414 $ 23,897 $ 16,321
========== ========== =========
NET INCOME ALLOCATION:
General partners $ 425 $ 239 $ 163
Limited partners 41,989 23,658 16,158
---------- ---------- ---------
TOTAL $ 42,414 $ 23,897 $ 16,321
========== ========== ==========
See notes to consolidated financial statements.
F-4
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' DEFICITS
YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(In Thousands)
- -----------------------------------------------------------------------------------------
General Limited
Partners Partners Total
BALANCE, JANUARY 1, 1998 $ (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)
Capital distributions (413) (40,815) (41,228)
Net income 425 41,989 42,414
--------- ----------- -----------
BALANCE, DECEMBER 31, 2000 $ (485) $ (49,161) $ (49,646)
========= =========== ============
See notes to consolidated financial statements.
F-5
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(In Thousands)
- --------------------------------------------------------------------------------------------------------------------------
2000 1999 1998
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 42,414 $ 23,897 $ 16,321
Adjustments to reconcile net income to net cash
provided by operating activities:
Start-up cost write-off - - 214
Cumulative effect of a change in accounting principle (7,866) - -
Depreciation and amortization 13,596 13,605 13,664
Loss on sale of equipment 17 - -
Increase (decrease) in cash resulting from a change in:
Restricted funds 6,205 (3,229) (1,696)
Accounts receivable (4,592) (1,730) 3,321
Due from affiliates (3,455) 316 (729)
Fuel inventory and supplies 138 (1,798) (97)
Other current assets (241) 138 5
Accounts payable (2,077) 1,509 (1,046)
Accrued expenses 8,410 (244) (2,171)
Due to affiliates 166 (170) 141
Deferred revenue (677) (584) 6,565
Other long-term liabilities 20 1,543 3,008
---------- --------- --------
Net cash provided by operating activities 52,058 33,253 37,500
---------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Plant and equipment additions (775) (488) (177)
---------- --------- --------
Net cash used in investing activities (775) (488) (177)
---------- --------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Restricted funds (1,293) (131) (2,674)
Distributions to partners (41,228) (27,919) (30,849)
Repayment of long-term debt (7,307) (4,822) (3,298)
---------- --------- --------
Net cash used in financing activities (49,828) (32,872) (36,821)
---------- --------- --------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS 1,455 (107) 502
CASH AND CASH EQUIVALENTS,
BEGINNING OF YEAR 1,732 1,839 1,337
---------- --------- --------
CASH AND CASH EQUIVALENTS,
END OF YEAR $ 3,187 $ 1,732 $ 1,839
========== ========= ========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest $ 34,082 $ 34,047 $34,349
========== ========= ========
See notes to consolidated financial statements.
F-6
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
- --------------------------------------------------------------------------------
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.
JMC Selkirk, Inc. is a wholly-owned subsidiary of Beale Generating Company
("Beale"), which is jointly owned by Cogentrix Eastern America, Inc. (10.9%
interest) and PG&E Generating Power Group, LLC (89.1% interest), a direct,
wholly-owned subsidiary of PG&E Generating Company, LLC, an indirect,
wholly-owned subsidiary of PG&E National Energy Group, Inc. ("NEG"). NEG is
an indirect, wholly-owned subsidiary of PG&E Corporation.
Because the California energy markets situation has caused financial
difficulties for Pacific Gas and Electric Company, a wholly-owned
subsidiary of PG&E Corporation, PG&E Corporation's credit ratings were
downgraded to below investment grade in January 2001, which caused PG&E
Corporation to default on outstanding commercial paper and bank borrowings.
In January 2001, certain corporate actions were taken to insulate the
assets of NEG and its direct and indirect subsidiaries from an effort to
substantively consolidate those assets in any insolvency or bankruptcy
proceeding of PG&E Corporation. In March 2001, PG&E Corporation refinanced
all of its outstanding commercial paper and bank borrowings, and Standard &
Poors subsequently removed its below investment grade credit
F-7
1. Organization and OPERATION (continued)
rating since PG&E Corporation no longer had rated securities outstanding.
Management believes that the NEG and its direct and indirect subsidiaries
as described above, including JMC Selkirk, would not be substantively
consolidated with PG&E Corporation in any insolvency or bankruptcy
proceeding involving PG&E Corporation.
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 accounting principles generally accepted in the United States of
America 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 gas are recorded in the month sold.
Staff Accounting Bulletin No. 101, Revenue Recognition ("SAB No. 101") was
issued by the Staff of the Securities and Exchange Commission ("SEC") on
December 3, 1999. SAB No. 101, as amended, summarizes certain of the SEC
staff's views in applying generally accepted accounting principles to
revenue recognition in financial statements. In addition, the Emerging
Issues Task Force ("EITF") issued EITF Issue No. 99-19, Reporting Revenue
Gross as a Principal versus Net as an Agent. The Partnership adopted these
related accounting pronouncements in 2000, resulting in a change in the
method of reporting the Partnership's fuel revenue. As a result of the
reporting change and the reclassification of prior periods for comparison
purposes, all of the Partnership's revenues from the sale of gas are
reported gross as operating revenue for all periods presented. The change
had no effect on the Partnership's net income or partners' capital, but
increased its revenues and fuel costs.
Other Comprehensive Income - The Partnership had no elements of other
comprehensive income that are required to be reported or disclosed in 2000,
1999, or 1998.
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.
F-8
2. Summary of significant accounting policies (Continued)
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, 2000 and 1999,
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. Capitalized
modifications to leased properties are amortized using the straight-line
method over the shorter of the lease term, through September 2014, or the
asset's estimated useful life. Other assets are depreciated as follows:
Cogenerating facility 30 years
Computer Systems 3 to 7
Office equipment 5
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.
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, 2000 and 1999.
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.
F-9
2. Summary of significant accounting policies (Continued)
Change in Accounting Principle (continued) - Effective January 1, 2000, the
Partnership changed its method of accounting for major maintenance and
overhauls to expensing the cost of major maintenance and overhauls as
incurred. Prior to January 1, 2000, the estimated cost of major maintenance
and overhauls was accrued in advance based on projected future cost of
major maintenance and overhaul using the straight-line method over the
period between major maintenance and overhaul. The Partnership implemented
the new accounting method by recording the cumulative effect of a change in
accounting principle in the consolidated statement of operations for the
year ended December 31, 2000. The cumulative effect of adopting the new
accounting principle was the recording of net income totaling approximately
$7,866,000 on January 1, 2000. The effect on the 2000 financial statements
was an increase of other operating and maintenance expense of approximately
$816,000. A major overhaul reserve is included in other long term
liabilities in the accompanying consolidated balance sheets at December 31,
1999 and had a carrying balance of approximately $7,866,000. Provision for
major overhaul totaling $1,624,000 and $1,814,000 for the years ended
December 31, 1999 and 1998, respectively, is included in other operating
and maintenance expenses in the accompany consolidated statements of
operations. If the cumulative effect had been recorded in 1998 or 1999,
then the pro forma effect (unaudited) for 1998 and 1999 would have
increased net income by approximately $1,437,000 and $1,323,000,
respectively.
New Accounting Pronouncements - The Partnership will adopt Statement of
Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative
Instruments and Hedging Activities, as amended by SFAS Nos. 137 and 138, on
January 1, 2001. This standard requires the Partnership to recognize all
derivatives, as defined in the Statement, on the balance sheet at fair
value. Derivatives, or any portion thereof, that are not designated and
effective hedges must be adjusted to fair value through income. If
derivatives are effective hedges, depending on the nature of the hedges,
changes in the fair value of derivatives either will offset the change in
fair value of the hedged assets, liabilities, or firm commitments through
earnings, or will be recognized in other comprehensive income until the
hedged items are recognized in earnings. The Partnership estimates that the
transition adjustment to implement this new standard will not effect net
income and will be a negative adjustment of approximately $8,968,000 to
other comprehensive income, a component of partners' equity. The
Partnership also has certain derivative commodity contracts for the
physical delivery of purchase and sale quantities transacted in the normal
course of business. At this time, these derivatives are exempt from the
requirements of SFAS No. 133 under the normal purchases and sales
exception, and thus will not be reflected on the balance sheet at fair
value. The Derivative Implementation Group of the Financial Accounting
Standards Board is currently evaluating the definition of normal purchases
and sales. As such, certain derivative commodity contracts may no longer be
exempt from the requirements of SFAS No. 133. When the final decision
regarding this issue is complete, the Partnership will evaluate the impact
of the implementation guidance on a prospective basis.
Reclassifications - Certain reclassifications have been made in the 1999
and 1998 consolidated financial statements to conform to the current-year
presentation.
F-10
3. Partners' capital
The general and limited partners and their respective equity interests are
as follows:
Interest
Partners Affilited 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
Aquila Selkirk, Inc.**** Aquila East Coast Generation, Inc.***** 13.55 20.00
RCM Selkirk LP, Inc.** RCM Holdings, Inc.*** 78.16 -
* Formerly Cogen Technologies Selkirk, GP, Inc.
** Formerly Cogen Technologies Selkirk, LP, Inc.
*** Formerly Cogen Technologies, Inc.
**** Formerly El Selkirk, Inc.
***** Formerly GPU International, Inc.
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 and Aquila East Coast Generation, Inc. ("Aquila
ECG"). 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%, Aquila ECG at 17.7%, and RCM Holdings,
Inc., at 17.5%.
4. Accrued Expenses
Accrued expenses consisted of the following at December 31 (in thousands):
2000 1999
Accrued fuel costs $ 13,877 $ 68,836
Accrued PILOT 2,900 2,700
Accrued utilities 969 899
Accrued operation and maintenance expenses 766 525
Accrued bond interest 368 375
Other accrued expenses 2,644 1,779
-------- ---------
Total $ 21,524 $ 13,114
======== =========
F-11
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 semiannually 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):
2001 $11,062
2002 13,529
2003 17,365
2004 19,587
2005 25,230
2006 and thereafter 287,053
-------
$373,826
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, 2000, the balance in the Major
Maintenance Reserve Fund was approximately $3,855,000.
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
semiannual payment date.
F-12
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,
2000, the balance in the Debt Service Reserve Fund was approximately
$23,978,000.
The Partnership Distribution Fund has the lowest priority in the fund
hierarchy. Cash distributions to the Partners from these subfunds 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 $7,542,428 through August 8, 2003. 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, 2000 and 1999, 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, 2000, 1999, and 1998, amounts
charged to fuel costs as a result of losses realized from these agreements
totaled approximately $2,463,000, $2,342,000, and $2,480,000, 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, 2000 and 1999 was
approximately $400,977,000 and $383,915,000, respectively.
F-13
6. FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)
Currency Swap Agreements - The currency exchange agreements do not have
stated values at December 31, 2000 and 1999. The fair value of the
currency exchange arrangements represents the termination liability of
approximately $8,968,000 and $9,036,000 at December 31, 2000 and 1999,
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 operates on a
"merchant-like" basis, whereby the Partnership has 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 $8,308,000 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 $5,304,000 and $5,981,000 in the accompanying
consolidated balance sheets at December 31, 2000 and 1999, 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, 2000, 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.
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.
F-14
7. Commitments AND CONTINGENCIES (continued)
Steam Sales Agreements (continued) - 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 that 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, 2000, 1999,
and 1998, the Partnership purchased gas totaling approximately
$55,917,000, $34,209,000 and $32,048,000, respectively, under these
agreements.
The Partnership has three 20-year firm fuel transportation service
agreements for Unit 1 commencing November 1, 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 has posted a letter of credit for approximately
$2,542,000 U.S. dollars, and two fuel suppliers, on behalf of the
Partnership, have posted letters of credit totaling approximately
$7,578,000 Canadian dollars under one of these agreements. The Partnership
will reimburse to the fuel suppliers all costs related to obtaining and
maintaining the letters of credit.
F-15
7. Commitments AND CONTINGENCIES (continued)
Fuel Supply and Transportation Agreements (continued) - The approximate
obligations to pay under Fuel Supply Agreements and Fuel Transportation
Agreements are as follows:
Fuel Supply Fuel Transportation
Agreements Agreements
-------------- -------------------
2001 $ 8,647,000 $ 45,606,000
2002 $ 8,863,000 $ 47,753,000
2003 $ 9,084,000 $ 48,922,000
2004 $ 9,311,000 $ 49,326,000
2005 $ 9,544,000 $ 48,870,000
2006 and thereafter $ 35,657,000 $ 424,545,000
-------------- ------------------
Total $ 81,106,000 $ 665,022,000
-------------- ------------------
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.
F-16
7. Commitments AND CONTINGENCIES (continued)
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):
2001 $ 2,900
2002 3,100
2003 3,300
2004 3,500
2005 3,700
2006 and thereafter 28,700
---------
$ 45,200
=========
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 October 31, 2007. 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.
On November 8, 2000, the Partnership signed a Consent to Field Audit
Adjustment in settlement of a gas import tax audit conducted by the New
York State Department of Taxation and Finance. The audit covered all gas
import activity beginning March 1, 1992 through August 31, 2000. This
audit resulted in a total assessment of approximately $1.5 million,
comprised of approximately $1.0 million of additional tax liability and
approximately $0.5 million of interest. As of December 31, 2000, the
Partnership has paid this assessment in full and no additional liability
exists.
F-17
8. RELATED PARTIES
JMCS I Management manages the day-to-day operation of the Partnership and
is compensated at agreed-upon billing rates that 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, 2000,
1999 and 1998, expenses incurred for services provided by JMCS I
Management totaled approximately $3,569,000, $2,027,000 and $2,651,000,
respectively. In addition, during the year ended December 31, 1999,
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 $559,000, $140,000, and $1,649,000, respectively, in
2000, 1999, and 1998, and gas sold to affiliates of JMC Selkirk, Inc.
totaled approximately $3,806,000, $453,000, and $1,476,000, respectively.
Gas purchases are recorded as fuel costs and sales of gas are recorded as
fuel revenues 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,
2000, 1999, and 1998, sales of energy, capacity and other services totaled
approximately $14,888,000, $5,515,000 and $2,009,000, 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. For the years ended December
31, 2000, 1999 and 1998, firm fuel transportation services totaled
approximately $8,227,000, $7,994,000 and $9,630,000, respectively. These
services are recorded as fuel costs in the accompanying consolidated
statements of operations.
* * * * * *
F-18
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(19) Amendment No. 5 to Credit Agreement, dated August 1, 2000,
between the Partnership and Dresdner Bank AG, New York Branch
10.1.7(1) Loan Agreement, dated as of May 1, 1994, between the Partnership,
Chase, as Agent, and other Bridge Banks identified therein
10.1.8(1) Amended and Restated Loan Agreement, dated as of May 1, 1994,
between the Funding Corporation and the Partnership
10.1.9(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
10.1.10(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
-38-
10.2.3(1) Second Amendment to Power Purchase Agreement, dated as of
January, 25, 1990, between JMC Selkirk and Niagara Mohawk
10.2.4(1) Third Amendment to Power Purchase Agreement, dated as of October
23, 1992 between JMC Selkirk and Niagara Mohawk
10.2.5(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 Letter Agreement dated as of October 9, 2000, between the
Partnership and Niagara Mohawk
10.2.9(1) Agreement dated as of March 31, 1994, between the Partnership and
Niagara Mohawk
10.2.10(5) Letter Agreement dated as of April 18, 1997, between the
Partnership and Niagara Mohawk
10.2.11(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
10.2.12(1) License Agreement between the Partnership and Niagara Mohawk,
dated as of October 23, 1992
10.2.13(1) Power Purchase Agreement, dated as of April 14, 1989, between Con
Edison Company of New York, Inc. ("Con Edison") and JMC Selkirk
10.2.14(1) Rider to Power Purchase Agreement, dated as of September 13,
1989, between Con Edison and JMC Selkirk
10.2.15(1) First Amendment to Power Purchase Agreement, dated as of
September 13, 1991, between Con Edison and JMC Selkirk
10.2.16(1) Letter Agreement Regarding Extending the Term of the Power
Purchase Agreement, dated as of May 28, 1992, between Con Edison
and JMC Selkirk
-39-
10.2.17(1) Second Amendment to Power Purchase Agreement, dated as of October
22, 1992, between Con Edison and JMC Selkirk
10.2.18(4) Third Amendment to Power Purchase Agreement, dated as of
September 13, 1996, between Con Edison and the Partnership
10.2.19(1) Letter Agreement Regarding Arbitration, dated October 22, 1992,
between Con Edison and JMC Selkirk
10.2.20(1) Letter Agreement Regarding Sale of Capacity above 265 MW, dated
as of October 22, 1992, between Con Edison and JMC Selkirk
10.2.1(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
10.2.22(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 and O&M 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) Second Amendment to Steam Sales Agreement, dated December 7,
1994, between the Partnership and General Electric
10.4.4(2) Third Amendment to Steam Sales Agreement, dated May 31, 1995,
between the Partnership and General Electric
10.4.5(1) Amended and Restated Operation and Maintenance Agreement, dated
as of October 22, 1992, between the Partnership and General
Electric
-40-
10.4.6(19) Second Amended and Restated O&M Agreement dated July 18, 2000,
between the Partnership and GE International Inc.
10.5 Fuel Supply Contracts
10.5.1(1) Amended and Restated Gas Purchase Contract, dated as of September
26, 1992, between Paramount Resources Ltd. ("Paramount") and the
Partnership
10.5.2(1) First Amendment to the Amended and Restated Gas Purchase
Contract, dated as of October 5, 1992, between Paramount and the
Partnership
10.5.3(1) 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")
-41-
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
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
-42-
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
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
-43-
10.8.1(1) Project Administrative Services Agreement, dated as of June 15,
1992, between JMCS I Management, Inc. ("JMCS I Management") and
the Partnership
10.8.2(1) First Amendment to Project Administrative Services Agreement,
dated as of October 23, 1992, between JMCS I Management and the
Partnership
10.8.3(1) Second Amendment to Project Administrative Services Agreement,
dated as of May 1, 1994, between JMCS I Management and the
Partnership
10.8.4(1) Water Supply Agreement, dated as of May 6, 1992, between the Town
of Bethlehem, New York and the Partnership
10.9 Real Estate Documents
10.9.1(1) Second Amended and Restated Lease Agreement, dated as of October
21, 1992, between the Partnership and General Electric
10.9.2(1) Amended and Restated First Amendment to Second Amended and
Restated Lease Agreement, dated as of April 30, 1994, between the
Partnership and General Electric
10.9.3(1) Unit 2 Grant of Easement, dated as of October 21, 1992, made by
General Electric in favor of the Partnership (regarding Unit 2
Substation and Transmission Line)
10.9.4(1) Declaration of Restrictive Covenants by General Electric, dated
as of October 21, 1992 (regarding Wetlands Remediation Areas)
10.9.5(1) Utilities Building Lease Agreement, dated as of October 21, 1992,
between General Electric, as Landlord, and the Partnership, as
Tenant
10.9.6(1) Easement Agreement, dated as of May 27, 1992, between Charles
Waldenmaier and the Partnership, as assignee
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
-44-
10.9.9(1) Sublease Agreement, dated as of October 21, 1992, between the
Partnership, as Subtenant, and the IDA, as Sublandlord
10.9.10(1) Amended and Restated First Amendment to Sublease Agreement, dated
as of April 30, 1994, between the Partnership and the IDA
10.9.11(1) Payment in Lieu of Taxes Agreement, dated as of October 21, 1992,
between the Partnership and the IDA
10.10 Security Documents
10.10.1(1) Assignment of Agreements, dated as of May 1, 1994, among Yasuda
Bank and Trust Company (U.S.A.) ("Yasuda"), Dresdner Bank AG, New
York and Grand Cayman Branches ("Dresdner"), the Depositary
Agent, the Collateral Agent, the Partnership and the Funding
Corporation
10.10.2(1) Depositary Agreement, dated as of May 1, 1994, among the Funding
Corporation, the Partnership, Bankers Trust Company as collateral
agent ("Collateral Agent") and Bankers Trust Company, as
depositary agent (the "Depositary Agent")
10.10.3(1) Equity Contribution Agreement, dated as of May 1, 1994, among the
Partnership, Cogen LP, Cogen GP, Makowski Selkirk and Chase
10.10.4(1) Cash Collateral Agreement, dated as of May 1, 1994, among
Makowski Selkirk, the Partnership and Chase, as Agent
10.10.5(1) Cash Collateral Agreement, dated as of May 1, 1994, among Cogen
LP, the Partnership and Chase, as Agent
10.10.6(1) Cash Collateral Agreement, dated as of May 1, 1994, among Cogen
GP, the Partnership and Chase, as Agent
10.10.7(1) Agreement of Spreader, Consolidation and Modification of
Leasehold Mortgages, Security Agreements and Fixture Financing
Statements, (the "First Consolidated Mortgage"), dated as of May
1, 1994, in the principal amount of $227,000,000 among the
Partnership, the IDA and the Collateral Agent
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
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10.10.9(1) Agreement of Spreader and Modification of Leasehold Mortgage (the
"Restated Mortgage"), dated as of May 1, 1994, in the principal
amount of $43,000,000 among the Partnership, the IDA and the
Collateral Agent
10.10.10(1) Agreement of Modification and Severance of Mortgage (the
"Mortgage Splitter Agreement"), dated as of May 1, 1994, among
the Partnership, the IDA and the Collateral Agent
10.10.11(1) Leasehold Mortgage (Substitute Mortgage No. 1), dated as of May
1, 1994, in the principal amount of $9,099,000 given by the
Partnership and the IDA to the Collateral Agent
10.10.12(1) Leasehold Mortgage (Substitute Mortgage No. 2), dated as of May
1, 1994, in the principal amount of $43,000,000 given by the
Partnership and the IDA to the Collateral Agent
10.10.13(1) Leasehold Mortgage (Substitute Mortgage No. 1), dated as of May
1, 1994, in the principal sum of $16,601,000 given by the
Partnership and the IDA to the Collateral Agent
10.10.14(1) Leasehold Mortgage (Gap Mortgage No. 2) in the principal amount
of $42,199,000, dated as of May 1, 1994, given by the Partnership
and the IDA to the Collateral Agent
10.10.15(1) Leasehold Mortgage, Security Agreement and Fixture Financing
Statement (the "Chase Mortgage"), dated as of May 1, 1994, given
by the Partnership and the IDA to the Collateral Agent
10.10.16(1) Amended and Restated Security Agreement and Assignment of
Contracts (the "Security Agreement"), dated as of May 1, 1994,
made by the Partnership in favor of the Collateral Agent
10.10.17(1) Pledge and Security Agreement (the "Partnership Pledge
Agreement"), dated as of May 1, 1994, from the Partnership in
favor of the Collateral Agent
10.10.18(1) Security Agreement (the "Company Security Agreement"), dated as
of May 1, 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
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10.10.20(1) Purchase Agreement and Transfer Supplement, dated as of May 1,
1994, among Chase, Dresdner, Yasuda, the Funding Corporation and
the Partnership
10.11 Other Material Project Contracts
10.11.1(1) Purchase Agreement, dated April 29, 1994, among the Funding
Corporation, the Partnership, CS First Boston Corporation, Chase
Securities, Inc. and Morgan Stanley & Co. Incorporated
10.11.2(1) Capital Contribution Agreement, dated as of April 28, 1994, among
the Partnership, JMC Selkirk, JMCS I Investors, Cogen
Technologies GP and Cogen Technologies LP (collectively, the
"Partners")
10.11.3(1) Equity Depositary Agreement, dated as of May 1, 1994, among the
Partnership, the Partners, Makowski Selkirk and Citibank, N.A. as
Special Agent
10.11.4(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
18(18) Letter regarding change in accounting principle
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
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99.4(15) Press Release of the Partnership, dated August 31, 1998
- -----------------
(1) Incorporated herein by reference to the Registrant's Registration Statement
on Form S-1 filed September 1, 1994, as amended (File No. 33-83618).
(2) Incorporated herein by reference to the Registrant's Quarterly Report on
Form 10-Q for the Quarterly Period Ended June 30, 1995 filed August 14, 1995.
(3) Incorporated herein by reference to the Registrant's Quarterly Report on
Form 10-Q for the Quarterly Period Ended June 30, 1996 filed August 13, 1996.
(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.
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(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.
(18) Incorporated herein by reference to the Registrant's Quarterly Report on
Form 10-Q for the Quarterly Period Ended March 31, 2000 filed May 15, 2000.
(19) Incorporated herein by reference to the Registrant's Quarterly Report on
Form 10-Q for the Quarterly Period Ended June 30, 2000 filed August 14, 2000.
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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.
By: JMC SELKIRK, INC.
Managing General Partner
Date: March 30, 2001 /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, 2001
- ----------------------
P. Chrisman Iribe
/s/ SANFORD L. HARTMAN Director March 30, 2001
- -----------------------
Sanford L. Hartman
/s/ JOHN R. COOPER Senior Vice President and March 30, 2001
- ------------------- Chief Financial Officer
John R. Cooper
/s/ ERNEST K. HAUSER Senior Vice President March 30, 2001
- ---------------------
Ernest K. Hauser
/s/ DAVID N. BASSETT Treasurer March 30, 2001
- ---------------------
David N. Bassett
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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, 2001 /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, 2001
- ----------------------
P. Chrisman Iribe
/s/ SANFORD L. HARTMAN Director March 30, 2001
- -----------------------
Sanford L. Hartman
/s/ JOHN R. COOPER Senior Vice President and March 30, 2001
- ------------------- Chief Financial Officer
John R. Cooper
/s/ ERNEST K. HAUSER Senior Vice President March 30, 2001
- ---------------------
Ernest K. Hauser
/s/ DAVID N. BASSETT Treasurer March 30, 2001
- ---------------------
David N. Bassett
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